ML20203G921
| ML20203G921 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 02/23/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203G899 | List: |
| References | |
| 50-352-97-10, 50-353-97-10, NUDOCS 9803030108 | |
| Download: ML20203G921 (44) | |
See also: IR 05000352/1997010
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos. 50 352
50-353
License Nos. NPF-39
NPF 85
Report Nos. 97 10
97-10
Licensee: PECO Energy
Facilities: Limerick Generating Station, Units 1 and 2
Location: Wayne, PA 19087-0195
Dates: November 18,1997, through January 19,1998
inspectors: A. L. Burritt, Senior Resident inspector
F. P. Bonnett, Resident inspector
J. D. Noggle, Senior Radiological Specialist, DRS
A. J. Blamey, Reactor Engineer, DRP
W. B. Higgins, Reactor Engineer, DRP
Approved by: Clifford Anderson, Chief
, Projects Branch 4
Division of Reactor Projects
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9803030108 980223
PDR ADOCK 05000352
G PDR
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EXECUTIVE SUMMARY
Limerick Generating Station, Units 1 & 2
NRC Inspection Report 50-352/97-10,50-353/97-10
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This integrated inspection included aspects of PECO Energy operations, engineering,
maintenance, and plant support. The report covers a 9-week period of resident inspection.
Operatigng
- Control room supervisors at both units logged over 100 Technical Specification
Limiting Conditions for Operations for primary containment isolation valves during
the follow up inspection and testing event. Overall, log entries were adequately
controlled. However, several issues involving the accuracy of the unified log were
identified by the inspection. The most significant of these was the failure to log
inat two safety systems were inoperable resulting in a violation of controls stated in
the Operation Manual for maintaining the unified log (Section 02.1).
Maintenance
- Overall, maintenance technicians completed the rep = ament activity of the 1D
125vdc safeguards battery well. However, there wee several housekeeping and
work practice issues which could have impacted battery operability (Section M1.3).
- The large number of similar hydraulic control unit (HCU) discrepancies identified
during PECO's follow-up investigation to an individual control rod that fully inserted
during a reactor protection system surveillance test indicated that inadequate
maintenance had been performed during the recent on line maintenance activities
and during prior maintenance activities. The Nuclear Maintenance Division (NMD)
appeared to have established adequate control and oversight of the on-line HCU
work activities and NMD technicians demonstrated a good awareness and
responsibility toward quality by stopping work to notify his supervision of a wiring
discrepancy. However, PECO did not establish adequate measures to assure that
the applicable design requirements were adequately maintained during HCU on line
maintenance resulting in a violation (Section M1.4).
- The licensee's response to the failure of the power monitor card in the Unit 1 RRCS
was excellent. The licensee promptly established RRCS operability and corrected
the problem. Adequate consideration was given to the method used to prevent an
inadvertent plant trip during the maintenance repair, including use of the training
simulation to heighten technician awareness (Section M1.5).
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- In general, Limerick has adequate control of portable and/or temporary equipment in
the reactor and turbine building such that it will not interact with equipment
important to safety. Furthermore, this program is strengthened by periodic
walkdowns and critiques with first line supervisors. However, while reviewing plant
housekeeping, the inspector noted several discrepancies that were not identifie by
the PECO staff. Further, in the case of the deficient bolting associated with tb ,
monorail hoist it appeared the condition existed for a long period of time (Section
M2.1 ).
- ST-6-076-360-1(2), Reactor Enclosure Secondary Containment Integrity
Verification, overstated the requirements to meat Technical Specification 3.6.5, by
equating the floor drain plugs with the components required to maintain secondary
containment. Control of the configuration of these plugs remains necessary to
prevent creating an opening in the secondary containment that would prevent the
standby gas treatment system from maintaining secondary containment in the event
of an accident. Inadequate control of the plugs demonstrated in October and the
lack of timeliness for incorporating the proposed procedure revision have resulted in
a violation (Section M8.1).
Enaineerina
- The PECO engineer demonstrated excellent awareness of component configurntion
by recognizing a mis wired closing circuit for an Unit 1 reactor core isolation cooling
steam isolation valve. Engineering promptly identified that the PCIVs were not
adequately tested and implemented adequate measure to complete the required
testing within the time allowed by technical specifications (Section E1.1).
- The engineering assessment and supporting safety evaluation to support operability
of the HPCI exhaust valve was inadequate in that it did not address the valve
closure time requirements. The plant operations review committee (PORC)
approved the safety evaluation, but failed to challenge the engineering assessment
discounting the requirement for the valve to close the first time to meet the closure
time required oy technical specifications in assessing operability. PORC accepted
the degraded condition of the valve without having identified the root cause or
evaluating the corrective actions to ensure future valve reliability and thereby the
ability to meet the required closure time (Section E2.1).
The use of a safety evaluation to accept the delay in further investigations and
testing of the HPCI exhaust valve, until the next scheduled refueling outage, in
effect inappropriately modified the technical specifications required closing time.
The use of the safety evaluation in addressing operability was not necessary nor
consistent with NRC guidance on operability provided in generic letter 91-18.
- The organization response to the D22 emergency diesel generator failing into the
isochronous mode of operation wa good, particularly since another EDG was
inoperable for planned maintenance and was competing for the same personnel
resources. The D22 EDG was returned to an operable status in about two and a
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half days after a thorough assessment of the overpower event which including a
variety of followup inspections and measurements. The root cause analysis of this
event was adequate; however, documentation weaknesses were noted including the
as found conditions not being documented in detailin the work order (Section
E2.2).
e The licensee appropriately implemented the commitment change process for the
main safety relief valve commitment change. Although the timing of NRC
notification for the change was sooner than required by the process, the letter was
misleading in that it implied that the change had been implemented as of the date of
the letter, whereas three months later at the end of the inspection period the
change had not been implemented. However, no violation of NRC requirements
was identified. In addition the engineering evaluation to support the modification of
the commitment was not comprehensive in that it did not correlate the performance
data to specific changes in the thresholds values (Section E6.1).
Plant Sucoort
e The radiation protection program controls for preveming internal exposures was
effective. No significant personnel exposures were apparent. However, the whole
body measurement capability appeared to lack sufficient rigor in assuring that all
internally deposited radio nuclides, that the whole body counting instrument was
expected to detect, were effectively identified and evaluated. It was not apparent
that staff were cognizant of the inherent limitations of the equipment relative to
discreet resolution of energy peaks to effect radio nuclide identification (Section
R 1.1 ).
e The respiratory protection program met regulatory requirements (Section R1.2).
e The air samplo counting laboratory provided properly calibrated and reliable sample
analysis services (Section R1.3).
e The inspector oetermined that the licensee's radiation protection instrument
calibration program generally utilized sound principles and techniques. However,
the process did not address or compensato for certain uncorrected calibration errors ,
that could eff 3ct instrument accuracy. Notwithstanding, the instrument calibration
process was cetumined to be effectively implemented. The TLD program oversight
was very effective in enhancing the accuracy of vendor TLD processing results
(Section R1.5),
e The bases upon which the licensee resolves exposure discrepancies between TLD
and electronic dosimeter quarterly results was not apparent. The area will be
further reviewed in a subsequent inspection (Section R4.1).
o Oversight of the ras.ation protection program consisted of independent and self-
assessments that generally provided for effective insights and recommendations for
program improvements (Section R7).
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e The Radiation Protection (RP) training program was adequate. The licensee
identified a weakness in the RP fundamentals training provided to RP technicians in
the continuing training program, and has made some progress in addressing this
concern (Section R5.1).
e The licensee has limited procedural controls over the advanced radiation worker
program. Some survey and contamination area deposting activities have been
performed by the advanced radiation workers that involved evaluation and
judgement determinations without qualified RP technician supervision. Further
investigation in the advanced radiation worker training and performance are needed
to determine whether a violation of TS 6.3.1 has occurred (Section R5.2).
- An unqualified person had been assigned to perform tasks which require formal
qualifiuation. Generally, there was evidence of direct supervision for the more
critical tasks performed by unqualified individual such as the performance and
evaluation of whole body counts. However, for administrative tasks, generally there
was no recorded evidence of direct supervision as required by the licensees training
and qualification procedures. Although, the practice of using unqualified and
unsupervised personnel is inconsistent with the licensee's procedure, this was
determined not to be a violation of regulatory requirements since the position or job
functions are not specifically addressed through the technical specification
requirements for the training of plant staff. However, the failure of the licensee to
appropriately control the use of unqualified personneIis of concern since the same
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procedure control are used to address positions which have specific training
requirements (Section R5.3).
- Although, the licensee was not in full compliance with Procedure ERP-600-1, Health
Physics Team, they were proactive in identifying the issues and their corrective
actions are adequate for preventing recurrence. The inspector also noted that
these issues were not identified in previous exercises or drills because the licensee
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had typically conducted their exercises during working hours in which HP
technicians were onsite and available for immediate response (Section P4),
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TABLE OF CONTENTS
Summ ary of Plant St atu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. Operations . . . . . . . . . . . . . . . . . . ..................................2
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
01.1 G e neral Com ments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
O2 Operational Status of Facilities and Equipment ...................2
O 2.1 Primary Containment isolation Valve Configuration Control . . . . . . 2
I I M aint e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
M1.1 General Comments on Maintenance Activities . . . . . . . . . . . . . . . 4
M1.2 General Comments on Surveillance Activities . . . . . . . . . . . . . . . 5
M1.3 Division 4 Safeguards 8attery Replacement - Unit 1. . . . . . . . . . . 5
M1.4 Hydraulic Control Unit Maintenance Activities . . . . . . . . . . . . . . . 6
M1.5 ReJundant Reactivity Control System Corrective Maintenance . . . 9
M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . 10
M2.1 Plant Material Condition Reviews: ..... ................ 10
M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
M8.1 (Closed) URI 97-03-01, Performance of Reactor Enclosure Secondary
Containment integrity Verification. . . . . . . . . . . . . . . . . . . . . . . 11
111. Eng i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
E1.1 Primary Containment Isolation Valve Configuration Error and
inadequate Te sting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
E2 Engineering Support of Facilities and Equipment .... ............ 15
E2.1 (Closed) LER 1-97-011 Unit 1 High Pressure Coolant injection (HPCI)
Turbine Exhaust Valve Failure . . . . . . . . . . . . . . . . . . . . . . . . . * 5
E2.2 Emergency Diesel D22 Loss of Control During Monthly Load Test
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E6 Engineering Organization and Administration ................19
E6.1 Main Safety Relief Valve Commitment Change . . . . . . . . . . . . . 19
IV. Pl a nt S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . .......................21
R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 21
R1.1 Internal Exposure Assessment . . . . . . . . . . . . . . . . . . . . . . . . . 21
R1.2 Respiratory Protection ..............................23
R1.3 Counting Laboratory Calibrations . . . . . . . . . . . . . . . . . . . . . . . 24
R 1.4 Release of Material from Turbine 8uilding Roof . . . . . . . . . . . . . 24
R1.5 Instrumentation Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
R2 Status of RP&C f acilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . 26
R4 Staff Knowledge and Performance in RP&C ....................27
R4.1 Exposure Discrepancy Reports . . . . . . . . . . . . . . . . . . . . . . . . . 27
R5 Staff Training and Qualification in RP&C , . . . . . . . . . . . . . . . . . . . . . 28
RS.1 RP Technician Training and Qualifications . . . . . . . . . . . . . . . . . 28
R5.2 Advanced Radiation Worker Program . . . . . . . . . . . . . . . . . . . . 28
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RS.3 Health Physics Personnel Qualification . . . . . . . . . . . . . . . . . . . 29
R7 Quality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . 31
-R8 Miscellaneous RP&C losues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2
R8.1 Dose Assessment Review of an August 2,1991 Contamination
incident ........................................32
P4 Staff Knowledge and Performance in EP , . . . . . . . . . . . . . . . . . . . . . . 32
V. M anageme nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3
X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
X2 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 5
ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
f LIST O F AC RO NYMS U S ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 6
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R,oort Details
Summary 3f Plant Status
Unit 1 began this inspection period operating at 100% power. The unit remained at full
. power throughout the inspection period with exceptions for testing, rod pattern
adjustments, and the following plant events.
- December 6 Operators entered a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shutdown limiting condition for
operation (LCO) in accordance with Technical Specification (TS) 3.6.3 after declaring several primary containment isolation
valves inoperable for not meeting all requirements. The valves
were properly tested and declared operable. Operators exited
the LCO prior to the end of the 12-hours,
e December 13 Operators reduced power to 65% to perform on-line
maintenance'on 52 hydraulic control units (HCUs),
Maintenance activities were completed and the unit returned to
full power on December 17.
e December 28 Operators reduced power to 70% to remove the 1 A
condensate pump from service after operator noted degraded
discharge pressure and significant vibration conditions with the
pump's performance. Unit power was increased to 77%
power during the period that maintenance technicians replaced
the pump. Operators restored the unit to full power on
- January 4,1998.
Unit 2 began this inspection period operating at 100% power. The unit remained at full
power throughout the inspection period with exceptions for testing, rod pattern
adjustments, and the following plant event.
- December G Operators entered a 12-hour shutdown LCO in accordance
with TS 3.6.3 after declaring several primary containment
isolation valves inoperable for not meeting all surveillance
requirements. The valves were properly tested and declared
operable. Operators exited the LCO prior to the end of the 12-
hours.
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1. Operations
01 Conduct of Operations'
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.
02 Operational Status of Facilities and Equipment
02.1 Primary Containment Isolation Valve Confiauration Control
a. Insocction Scone
On December 5, an engineer inspecting the breaker cubical for the Unit 1 reactor core
isolation cooling (RCIC) inboard steam isolation valve (HV-491F007) identified a mis wired
closing circuit (see Section E1.1). During the subsequent investigation the engineering
staff identified a testing deficiency that potentially affected the operability of numerous
other primary containment isolation valves (PCIVs). Between December 5 and 7 (about 48
hours), the operations staff maintained control of safety-related system operability per TS
during the plant wide follow-up investigation and testing of the affected motor operated
valves at both units. The inspector reviewed the unified control room log and the LCO log
I to ensure the appropriate LCO entries were made for PCIV and safety system inoperability.
The inspector discussed his findings with representatives of the Operations Department
staff. A Performance Enhancement Program (PEP 10007700) evaluation was initiated to
address the inspectors concerns,
b. Observations and Findinas
Shift management entered over 100 TS LCO entries into the control room's unified log in a
48-hour period. The unified log is a computer based log that records riarrative log entries
from both unit reactor operators, the chief operator, control room supervisor (CRS) and
Shift Manager. The log also tracks TS LCO entries. During the 48-hour period, a unit
supervisor was assigned to each unit to assist the CRS in maintaining control of the large
number of TS LCO entries at both units for the inspection and testing of the effected valve
motor operator circuits. Overall, the activities were generally performed well, with the
exceptions noted below.
Station engineers determhd that tne closing circuita for the PCIVs had r.ot been
adequately tested. Therefore, shift management entered TS 4.0.3, allowing 24-hours to
satisfy the missed surveillance testing prior to having to implement the required action as
per the TS LCO. Shift management entered this TS at 10:30 a.m. of December 5. The
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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consequences for not completing the required surveillance testing within the 24-hour
period would be to shutdown both units within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. While technicians tested each
PCIV, the unit supervisor also entered the four hour action statement for TS 3.6.3 (primary
containment isolation valves) as appropriate.
The inspector identified several problems from the unified log review. Two safety related
systems were made inoperable during the valve testing and no TS LCO log entry for the
system's inoperability was made in the unified log. The Unit 2 suppression pool spray
mode of residual heat removal (RHR) system (TS 3.6.2.2) and high pressure coolant
injection (HPCI) system (TS 3.5.1.c.2) were made inoperable (separately) for about two
hours. The inspector verified that all alternate and low pressure coolant injection systems
were operable during the time both systems were unavailable as required in each of the
associated TS action statements. Therefore, the technical specifications for these two
cases were technically met. Hewever, Operations Manual OM-L-12.1, Rogulatory Action,
step 4.4, requires a narrative log entry in the unified log for the safety system inoperability
LCO numbers were not unique. Several factor = caused this problem including:
- Duplicate LCO numbers were created when log entries were mMe within the
10-minute time period between system updates.
- LCO entries were inadvertently edited, changing the LCO from the original
entry.
- The same LCO number was repeated several time throughout the year for
different iS LCO entries.
The above mentioned variations were apparently caused by the computer software. For
example, if the operator intended to initiate an LCO entry, the computer displayed the next
chronological TS LCO entry number. This number, however, appeared on every computer
terminal that allowed more than one supervisor to be entering differing TS LCOs with the
same number. Operations management stated that the computer system software was
unable to keep pace with the large number of entries made from multiple terminals.
Further, the inspector identified several significant typographical errors, These included a
TS LCO closure at midnight, about six hours prior to the time logged initiating the LCO, and
a core spray (system 52) valve that was typed as an RHR valve (system 51). The
inspector raised concerns regarding the frequency and quality of log reviews performed by
operations supervision. Operations management assured the inspector that the unified log
is the official record of plant activities and that it was crucial that the log be complete and
accurate.
Operations management agreed with the discrepancies noted, but stated that they were
administrative in nature and in no case did they result in the inappropriate control of
equipment operability or in non-compliance with TS. Management also stated that no
narrative log entry was made for making the Unit 2 HPCI and suppression pool spray
systems inoperable, however, a narrative log entry would be reconstructed and a late log
entry made. Notwithstanding management's intent, the inspector presented his findings to
the operations management three days following the event and no edits had been made in
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the log up to that point. Therefore, the inspector concluded that the log did not accurately
reflect conditions as they occurred in the plant. OM-L-8.2, Narrative Logs / Scope of
Entry, states that items are to be entered into the log pertaining to system operability or
affecting the station. This action was not performed on two occasions. This is a violation.
(NOV 9710-01)
c. Ggnclusion
Control room supervisors at both units logged over 100 Technical Specification Limiting
Conditions for Operations for primary containment isolation valves during the follow up
inspection and testing event. Overall, log entries were adequately controlled. However,
severalissues involving the accuracy of the unified log were identified by the inspection.
The most significant of these was the failure to log that two safety systems were
inoperable resulting in a violation of controls stated in the Operanns Manual for
maintaining the unified log.
II. Maintenance
M1 Conduct of Maintenance
M 1.1 General Comments on Maintenance Activities (62707)
The inspectors observod 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 1 Division 4125vdc Safeguards Battery Replacement - November 18 -
21;
e Unit 1 High Pressure Coolant Injection Inboard Steam Valve Backseating -
November 19;
- Unit 2 D2318-month inspection, December 8 - 12;
Observed maintenance activities were conducted well using approved procedures, and
were comp!eted with satisfactory results. Comn.unications between the various work and
support groups were good, and supervisor oversight was good.
Overview of Raisina M/G Set Stoos Der SP-147
The inspector observed the adjustment of the 1B reactor recirculation motor generator
scoop tube stops. The reactor operator and control rooni crew had effectively minimized
distractions during this adjustment. Contingency procedures were opened and ready if
required during the adjustment. The maintenance and engineering personnelinvolved in
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the physical adjustment at the scoop tube positioner were aware of the potsntial reactivity
effect associated with working on this equipment. The supervisor in the field was aware
of the requirement for a senior reactor operator (SRO) to control this evolution. The
adjustment was completed satisf actorily.
M1.2 Ger ;ral Comments on Surveillance Activities (61726)
The inspectors observed selected surveillance tests to determim whether approved
procedures were in use, details were adequate, test instrumentation was properly
eclibrated 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:
- Unit 2 D23 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Endurance Test and Hot Restart December 15;
- Unit 2 Inservice Inspection Functional Pressure Test of HPCI Pump
Discharge and Turoine Exhaust Piping December 17;
- Unit 2 HPCI Quarterly Surveillance Test December 17;
- Unit 2 D21 Weekly Surveillance Test, December 31;
Observed surveillance tests were conducted well using approved procedures, and were
completed with satisf actory results. Communications betwocn the various work and
support groups were good, and supervisor oversight was good.
M1.3 Division 4 Safenuards Batteiv Reolacement - Unit 1
a. Insocction Scons
During the week of November 17, maintenance electricians and l&C technicians replaced
completely the Division 4125vde safeguards battery. Th work acSvities included
replacing the 60 battery cells and the inter f onnecting hardware, and inspecting and
cleaning of the battery rack. The inspector observed portions of the activity and discussed
the observations with several maintenance representatives. The inspector reviewed the
operations log for appropriate TS LCO entries,
b. Observations a.nd Findinns
The technicians completed the activity over a four day period, replacing 15 cells per day
without making the battery inoperable. The battery was maintained operable throughout
the evolution by jumpering the 15 cells to be replaced with a temporary safeguards
battery. The temporary battery is maintained in the same condition as the inservice
battery, is mounted in a seismically qualified cart, and meets the requirements of technical
specifications.
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The inspector noted soveral deficiencies in housekeeping and maintenanco practices during
the first day's activities. A temporary battery charger was lef t unattended without being
properly secured. Battery cables from the temporary battery were routad through and/or
tied to structural supports without using a sof toning material to protee'. the cabbs from
cheffing from the sharp edges of the support. One sable was routed und':r a florescent
lamp fixturo. The inspector raised concern that the cablo may have affected the seismic
class ll ovaluation for the lamp fixture over the seismic class I component. Tools were not
stored properly and an atmosphere monitoring device was lef t on a panel overtop of the
temporary battery. Further, a battery lead, disconnected from the removed battery cells,
was routed through the battery support rack to keep it out of the way, presented a
potential electrical hazard. The inspector discussed thoto observations with the
maintenanco foreman.
Revisiting the area the next day, the inspector observed general improvement in the
condition of the battery room. The temporary battery cables were routed through an
industrial cable guard on the floor, tools and other materials were properly stored, and the
disconnected battery cable properly isolated. A sei .mc engineer evaluated the overhead
lighting and determined that the cable running under the lamp did not present a concern.
The seismic class 11 over class I concern deals with the S hooks used to suspend the lamp
from the ceiling. The lamp could possibly be jarred out of the S hooks if the hook was not
closed or scaled properly, in this case, the S hooks were closed and sealed and therefore
did not croate a problem.
The inspector noted that this was the first battery replacement performed by the
maintenanco electricians. The task had been the responsibility of the I&C technicians and
was now being turned over to the electricians,
c. Conclusion
Overall, maintenance technicians completed the replacement 1ctivity of the 1D 12Svde
safeguards battery well. However, there were several housekeeping and work practice
issuos which could have impacted battery operability.
M1.4 Hydraulic Control Unit Mairitenance Activities
a. Insocetion Scone (62707)
Several maintenance related activities involving HCU's at both units occurred during the
inspection period. PECO Energy's Nuclear Maintenance Division (NMD) performed an on-
lino maintenance outage on selected Unit 1 HCUs beginning on December 12. On
December 26, at Unit 2, a single control rod fully inserted without operator acti?n during
the performance of a reactor protection system (RPS) surveillance test. The inspector
observed portions of the on line maintenance activities performed at the HCUs. Further,
the inspector reviewed the Unit 2 event, the PEP ovaluation, and d scussed the event with
several PECO representatives.
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b. Observations and Findinas
Hydraelle Control Unit On line Maintenance Unit 1
The HCU maintenance focused on replacing the remaining scram solenoid pilot valve
(SSPV) assemblies which utilized diaphragms made of BUNA-N material. Maintenance
technicians used maintenance procedure M 047 027, Preventive Maintenanc for HCUs,
throughout the activities. NMD technicians replaced 52 SSPV assemblies over a five day
period.
Work activities were planned, coordinated, and executed well between the Operations and
NMD Departments, and the reactor engineering staff. Optrators and reactor engineers
performed t,large number of control rod manipulations with3ut error. Further, NMD
personnel performed clearance and tagging responsibilities, maintenance activities, and '
HCU restoration without error. Following HCU restoration, operators performed scram time
testing to verify the control rod's operability.
A technician identified a wiring discrepancy at HCU 38 43. The wiring for the SSPVs (V-
117 and V 118) was found reversed. The technicians found the V 117 wired to the
terminals supplied by 'D' reactor protection system (RPS) and V 118 wired to the terminals
supplied by 'A' RPS. The technician immediately stopped work and notified his supervisor.
Technicians checked all other HCUs to determine the scope of the problem No other
discrepancies were noted.
The system manager issued Non Conformance Report (NCR) 97 03427 to address the
issue. The NCR determined that the HCU would have performed its scram function
regardless of which RPS bus the eSPVs were wired to. Further, the configuration problem
did not present a single f ailure concern or have an impact on channel separation, and
therefore was operable. The inspector found NCR's determinations to be acceptable.
Maintenance was last performed on the HCU during an overhaulin 1993.
As a result of this discrepancy, NMD revised procedure M-047 027 to include several
procedural enhancements. A ' Note' to enhance the po ' identification of the V-
117/118 SSPVs was added to the section for the SSPV replacement, as well as improved
wire identification, and the wiring termination locations. The inspector determined that the
safety consequances of this discrepancy were minor,in that, the scram function of the
HCU was not effected by the wiring configuration. Further, the procedures changes
appeared to enhance HCU wiring configuration control.
Sinale Control Rod Scram Durina Reactor Protection System Surveillance - Unit 2
On December 20, a single control rod fully insarted without operator action during the
performance of a reactor protection system (RPS) surveillance test. An l&C technician was
performing ST 2 042 645 2,RPS and NSSS Steam Dome Pressure, Channel A Functional,
when the event occurred. The control room staff notified the NRC per the requirements of
10 CFR 50.72(b)(2)(li), but later retracted the notification.
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Control room operators immediately entered off normal procedure, ON 104, Control Rod
Problems, verified that control rod 10 47 was fully inserted, and verified all thermallimits
were normal. The shift manager declared the control rod inoperable and directed that the
HCU be hydraulically isoleted. Nuclear Maintenance, l&C personnel, and reactor engineers
initiated troubleshooting activities under troubleshooting control form TCF 97 0905.
The plant staff's inves: Jation at the HCU revealed !cose terminal block connections on the
load side leads to SSPV supplied from the 'B' RPS channel. The terminal block screws X
were found to be backed off about three to four turns. The plant personnel at the HCU *
observed that the SSPV de energized intermittently when the l&C techrt ien attempted to )
i tighten the scrown. The reactor engineer hypothesized that the SSPV supplied ...,m B RPS
l channel de energlwd due to the loose connection prior to or when the surveillance test
initiated the A RPS half scram signal. The I&C technician tightened the connections and
reactor engineers performed a partial scram timing test to prove the operability of the
Technicians performed an inspection of all Unit 2 HCUs for similar problems and found 22
other HCus with variations of the same discrepancy. These findings were documented in
PEP 10007742. Several other maintenance discrepancies were also identified and
corrected during thir inspection. A terminallug was improperly landed at HCU 38-07. The
lug was held in place by the screw head " pinching" down on the outside of the lug
because the screw did not fit through the eyelet of the lug. At HCU 34 27, the technicians "
found a loose screw that had backed out to its last two threads. The inspection at Unit 1
identif%d v lCU discrepancios. One HCU was found with a cross threaded terminal
screw.
The inspector reviewing the maintenance history of the affocted HCUs determined that
HCU 10-47 was last worked in January 1996 as were 13 other of tne 32 HCU identified at
both units during this event. 11 HCUs were worked during the recent on-line maintenance
activities in November and December 1997, one in March 1997, two in July 1995, and
four HCUs were worked in December 1994. The inspector determined that the above
examples demonstrated inadequate maintenance of the in-flaid changes cerformed during
these previous on line maintenance activities.
The inspectors concluded that the safety consequence of the event was minimal, but was
concerned with the large number of examples of poor quality craf tsmanship and design
control during on line maintenance. Appendix 0, Criterion lil, of 10 CFR 50 states, in part,
that measures shall be provided for verifying or checking the adequacy of design changes
performed during maintenance and repair, and that design changes, including field changes
shall be subject to design control measures commensurate with those applied to the
original design. Contrary to the above, PECO did not establish adequate measures to
assure that the applicable design requirements were ad3quately maintained during HCU on-
line maintenance. This was a violation of 10 CFR 50, Appendix B, Criterion Ill. (NOV 97-
10 02)
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PECO retracted the four hour notification of the event based on the guidance of NUREG-
1022,(Event Reporting Guidelines 10 CFR 50.72 and 50.73). The single control rod
insertion was not considered an ESF actuation by itself and was not the result of an
actuation of the RPS system. Further review by reactor engineering determined that the
capability of the RPS and scram function of all control rods was not adversely impacted by
the identified loose screws,
c. Conclusion
The large number of similar hydraulic control unit (HCU) discrepancies identified during
PECO's follow up investigation to an individual control rod that fully inserted during a
reactor protection system surveillance test indicated that inadequate maintenance had been
performed during the recent on-line maintenance activities and during prior maintenance
activities. The Nuclear Maintenance Division (NMD) appeared to have established
adequate control and oversight of the on line HCU work activities and NMD technicians
demonstrated a good awareness and responsibility toward quality by stopping work to
notify his supervision of a wiring discrepancy. However, PECO did not establish adequate
measures to assure that the applicable design requirements were adequately maintained
during HCU on line maintenance as required per 10 CFR 50, Appendix B, Criterion ill,
Design Control.
M1.5 Redundant Reactivity Control System Corrective Maintenance
a. [03nection Scone (71707)
A review of the licensoo corrective action response to the failure of a power monitor card
in the Unit 1 Mundant Reactivity Control System (RRCS) Division I was performed. The
inspector reviewed the logs and discussed the f a'. ure with operators and the RRCS system
manager,
b. Observations and Findinag
On October 18, Unit 1 received a Division i RRCS Out of Service annunciator and an
equipment operator was sent to investigate. The equipment operator reported that a "181
310 PWR MON TST/PWR SUPPLY FAILURE" error was displayed on Division i RRCS. The
RRCS would not reset and an equipment trouble tag was written to document the f ailure.
Subsequent troubleshooting identified that the power supplies were functioning and that
the power monitor card had f ailed indicating that all RRCS functions were still operable.
On October 20, the licensee successfully replaced the f aulty power monitor card with the
RRCS energized returning the RRCS a to fully operational condition.
Prior to implementing repairs, the licensee cont.ulted the RRCS vendor, to determine if the
power monitor card could be replaced with the system energized without causing an
inadvertent trip. The vendor indicated that a trip should not occur but could not guarantee
this assessment. The licensee also verified with the vendor that an updated power monitor
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card stocked in their supply system was completely compatible with the earlier model
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power monitor card that was malfunctioninc. To provide further assurance, the licensee
simulated the power monitor card replacemint on a RRCS training simulator on loan from
another plant and determined that the card replacement would not cause an inadvertent
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trip.
The licensee system manager indicated that, although there is no regulatory time
constraints involved, repair of the RRCS is treated as an immediate concern since a faulty
RRCS can cause an inadvertent plant trip.
c. Conclusions
The licensee's response to the f ailure of the power monitor card in the Unit 1 RRCS was
excellent. The licensee promptly established RRCS operability and corrected the problem.
Adequate consideration was given to the method used to prevent an inadvertent plant trip
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during the maintenance repair, including use of the training simulator to heighten technician
awareness.
M2 Maintenance and Material Condition of Facilities and Equipment
M 2.1 Plant Material Condition Reviews:
a. Insoection Scone
Plant walkdowns specifically focused on equipment important to safety were conducted to
overview the plant material condition. This inspection also reviewed procedure A C 030,
Plant Material Condition and Housekeeping Controls which describes the licerisee's
controls for material condition,
b. Observations and Findinag
The general plant areas in the reactor and turbine build'..gs were free of clutter.
Emergency lighting necessary for plant shutdown under some postulated conditions
appeared to be aimed at appropriate equipment and showed an acceptable battery charge.
In general, material storage was away from equipment important to safety and properly
anchored. Sensitive equipment that could initiate a plant transient was clearly labeled to
caution personnel. The inspector noted that periodic walkdowns and critiques of
housekeeping areas are performed by peer first line supervisors. However, several
deficient conditions were identified N the inspector and are described below.
A large structural steel support for a monorail hoist that penetrates the Unit 1 primary
containment access door had five of eight nuts not engaging the embedment plate in
several cases the nuts were backed off as much as an inch and appeared to have been in
this condition for some time since the exposed threads had been painted, in response to
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the discrepancy the licensee performed a field walkdown and removed the hoist from
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l service. The initial engineering review determined that this was a non conforming
condition, but the lateral supports would ensure that seismic loads would not damage the
containment door. The licensee plans to complete the engineering evaluation and
ultimately corrected the condition.
The inspector identified the instrument line to the Unit 2 Pressure Transmitter, PT 001
207, was vibrating. This is a small diameter line that provides the high pressere turbine
exhaust signal to the electro hydraulic control (EHC) system. This signal is utilized to
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provide a turbine trip if a load imbalance is sensed between the generator output and the
turbine power. Engineering reviewed the configuration of this line and initiated equipment
trouble tag (ETT) to provid) better support and reduce the vibration of the instrument line,
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Walkdown of the surrounding area did not identify any safety related equipment that could
be impacted by the failure of this small diameter steam line. The Unit 1 instrument line
was configured differently and had no observed vibration. i
The inspector identified two spare cubicles in 250 Volt DC MCC 1DB 1 that were open to
the reactor building atmosphere since no breaker was installed. Engineering determined
! that there was no environmental qualification (EO) concern because this area was not
subjected to high humidity following accident. However, the engineering staff also
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determined that the opening should be covered to prevent foreign material from entering
the cubicle. The system manager has initiated corrective actions to provide foreign
material barriers to cover these openings.
The inspector identified a minor issue, in which an unsecured cart was found next to a
safety related 480 vac motor control center (MCC D114 R-GU. The cart was promptly
removed af ter being brought to the attention of the control room staff,
c. Conclusions
In general, Limerick has adequate control of portable and/or temporary equipment in the
reactor and turbine building such that it will not interact with equipment important to
safety. Furthermore, this program is strengthened by periodic walkdowns and critiques
with first line supervisors. However, while reviewing plant housekeeping, the inspector
noted several discrepancies that were not identified by the PECO staff. Further, in the
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case of the deficient bolting associated with the monorail hoist it appeared the condition
existed for a long period of time.
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M8 Miscellaneous Maintenance !asues (92902)
M8.1 (Closed) URI 97 03-01, Performance of Reactor Enclosure Secondarv Containment
inteority Verification.
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a. Inspection Sqqp.g
The inspector raised concerns with the Operation Department's methodology to verify the
condition of plugged floor drains during the performance of ST 6-076 3601(2), Reactor
Enclosure Secondary Containment Integrity Verification. The concern focused on whether
an operator reviewing the locked valve log only, to determine that the floor drain plug's
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condition, met the requirements of the TS. Operations management enhanced the
procedure to include the review of the Barrier Breach Log (A C 134), and the LCO and
potential LCO logs. The inspector lef t the item unresolved pending the determination of
whether any violations using th6 original methodology had occurred. During the current
inspection period, the inspector discussed the issue with several engineering
representatives.
b. Observations and Findinas
PECO regulatory engineers defined the word " verify", as it is used in the Technical
Specifications (TS 4.6.5.1.1.B.), to clarify confusion that resulted from discussions within
various plant organizations over compliance with ST 6-076 3601(2). They determined
" verify" was to prove to be true by demonstration; to confirm or substantiate by
investigation, comparison with a standard, or reference to the facts. Regulatory concluded
that the intent of " verify" was to physically check the required configuration as much as
practical, and then refer to the next best alternative that provided relative assurance that
the configuration was correct based on the last known change to the configuration.
The engineering staff does not consider the floor drain plugs to be a Technical
Specification penetration required to be closed during an accident condition. This is based
upon establishing and maintaining secondary containment (a O.25 inch of vacuum water
- gage) with the standby gas treatment system (SGTS) and by the satisfactory completion of
the required TS surveillance which limits the scope of penetrations requiring surveillance to
doors, hatches, dampers, and valves. The SGTS is able to maintain the negative pressure
with a design leak tightness of 2500 cfm or lesi PECO conservatively had included the
floor drain plugs in the monthly surveillance test, although they were not explicitly required
by the TS definition for secondary containment. An engineering analysis indicated that the
rerroval of a small number drain plugs does not impede SGTS ability to maintain secondary
containment, but the removal of a significant number of drain plugs would. The engineers
therefore stated that tight configuration controls for the removal of drain plugs would
continue to be required and that an engineering evaluation would be performed to
determine the amount of air inleakage presented by the opening when several drain plugs
were removed to ensure the TS inleakage limit was not exceeded.
The int pector noted a licensee identified event that occurred on October 7,1997,in which
a floor drain plug at Unit 2 wha unlocked and removed from drain FD 74 without proper
configuration controls as stated in A C 8, Lantrol of Locked Valves and Devices. The
equipment operator (EO), performing GP-7, Plant Winterization, contacted and discussed
opening the fioor drain at Unit 1 with a licensed operator because he could not contact the
flex supervisor or the control room supervisor. Subsequently, the EO proceeded to Unit 2
to perform the same task. The EO, however, did not contact the control room prior to
opening the Unit 2 floor drain because he believed that his previous conversation covered
both units. The following day, another EO found the Unit 2 drain opened and that it had
been opened for about 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />.
The inspector determined that this activity did not meet PECO's configuration controls as -
stated requirements of A C-8. A C 8, steps 7.2.2 and 7.2.3 states, in part, that the
individual requesting permission for the manipulation (of the locked device) should enter
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the valve or device laformation in the Locked Valve Log and obtain permission from the
Shif t Management. Shift Management shall then indicate authorization for the
manipulation by initiating and dating the Log entry. The EO did not properly fill out the
Lock Valve Log nor was Shif t Management approval granted prior to removing the floor
drain. The inspector determined that this activity was a vlotation. (NOV 9710-03)
The ST currently reflects the floor drains as a TS required component. PECO intends to
revise the ST to remove the asterisk defineating the component as a TS requirement. The
floor dreins will continue to be checked as stated in the ST. The difference being that they
will not have to be " verified" as required by TS. The inspector agreed that floor drains are
not defined penetrations as per TS, and drain plugs should not be equated with .
components required to maintain secondary containment integrity, as was discerned m the
ST. However, the ST was the only document delineating what components were
specifically required to meet the TS, configuration of the floor drains was not adequately
controlled through the normal vehicle (A C 8), and the proposed revision to the ST has not,
to date, been performed.
c. Conclusion
ST 6 076 3601(2), Reactor Enclosure Secondary Containment Integrity Varification,
overstated the requirements to meet Technical Specification 3.6.5, by equating the floor
drcin plugs with the components required to maintain secondary containment. Control of
the configuration of these plugs remains necessary to prevent creating an opening in the
secondary containment that would prevent the standby gas treatment system from
maintaining secondary containment in the event of an accident, inadequate control of the
plugs demonstrated in October and the lack of timeliness for incorporating the proposed
procedure revision have resulted in a violation.
Ill. Engineering
E1 Conduct of Engineering
E1.1 Primary Containment Isolation Valve Confiouration Error and inadeauste Testina
a. Insoection Scoce
On December 5, an engineer inspecting a breaker cubicle identified a mis wired closing
circuit for the Unit 1 reactor core isolation cooling (RCIC) inboard steam isolation valve
(HV 491F007). A contact that bypasses the closed limit switch and thermal overload
protection had been incorrectly terminated. During the subsequent investigation, the
engineering staff also identified a testing deficiency,
b.- Observations and Findinas - ---
The engineer recognized that circuit in the AC cubicle was wired in the configuration
normal for a DC breaker. Normally in the AC cubicle, the 42 C contact is terminated at
- terminal block 5&6 and is terminated at terminals 21&22 for the DC.
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The circuit, as wired, would permit the closed limit switch instead of the torque switch to
stop valve motion during an automatic isolation. Consequently, the valve may not close
fudy into the seat, creating the poten'.lal for leakage past this primary containment isolation
valve (PCIV). The licenses declared the RCIC inboard steam isolation valve inoperable and
isolated the penetration to comply with technical specifications.
The licensee identified that the computerized wire termination data base was consistent
with the mis wired RCIC circuit. The licensee evaluated the data base and determined that
a nutriber of PCIVs had the same or similar type closing circuits. Further review found
three additional database descriptions that appeared to be discrepant. Field inspections of
these three discrepancies revealed only one additional valve, the Unit 1 RCIC exhaust line
vacuum breaker, with the same mis wiring. The licensea also identified that the PCIVs
were not adequately tested. Specifically, the control circuit in question contains two
parallel paths; one for manual operation with thermal overload protection and thu other for
automatic isolation with the thermal overload protection bypassed. Both these paths are
energized during automatic valve isolation. The licensee identified that a failure of the
bypass contact could be masked by the proper operation of the valve via the thermally
protected portion of the circuit. Therefore, the test did not verify that a containment
isolation signal would fully close the valve with the thermal overload protection bypassed,
as required by technical specifications. The licensee implemented the appropriate technical
specification requiremot (s and subsequently tested the bypass contact for all affected
valves. All out one PCIV functioned correctly when proporly tested and the licensee
addressed this malfunction.
The valve mis wiring problern was identified by an engineer during a breaker cubicle
inspection to evaluate the use of some non quality parts. The licensee also determined
that the problem was introduced during a construction modification to add a closed limit
switch contact to address another issue with torque switch re-closure following valve
isolation.
The mis wired valve circuit and associated drawing issues are unresolved (URI 97-10-04)
pending NRC review of the licensee's identification of the root cause and implementation
of corrective actions. The inadequate testing issue is also unresolved (URI 9710-05)
pending NRC review of the licensee's identification of the root cause and implementation
of corrective actions,
c. Conclusion
The PECO engineer demonstrated excellent awareness of component configuration by
recognizing the terminal mis wiring. Engineering promptly identified that the r ':lVs were
not adequately tested and implemented adequate measure to complete the rs uired testing
within the time allowed by technical specifications.
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E2 Engineering Support of Facilities and Equipment
E2.1 (Closed) LER 1 97 011 Unit i Hlah Pressure Coolant inlection (HPCI) Turbine
Exhaust Valve dailure
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a. inspection Scop.g
On January 8,1998, the HPCI Turbine Exhaust Valve failed to stroke fully closed on the
first attempt during a routine valve stroke time surveillance test. The inspector reviewed
the engineering evaluations and corrective actions performed to address the survaillance
test f ailure,
b. Observations and Findinns
During stroke time testing of the HPCI turbine exhaust valve (HV- >1 F072L a loud
grinding noise was heard at the valve and the valve operator torque switch actuated,
stopping valve movement. The normally opca valve stopped at approximately twenty five
percent closed during the close stroke. The valve was then re opened and during a
subsequent attempt the valve closed without incident. This valve is a remote manual
containment isolation valve that is required, by technical specifications, to close within 120
seconds. Although the valve does not have an automatic isolation function, it is necessary
to isolate the HPCI system considered to be an c.'. tension of the containment boundary, in
the event of a HPCI system leakage. The valve was declared inoperable and closed to
comply with the primary containment isolation techn cal specifications.
The failure of a primary containment isolation valve and the associated isolation of HPCI
which caused the loss of the high pressure injsction safety function was reviewed for
reportability and appropriately found to be not reportable. Although the valve condition
resulted in the isolation of HPCI to comply with technical specifications, the PCIV
deficiency, by itself, would not have resulted in a loss of the a safety function prior to
identification and resultant actions taken by the operators. Tho inspector noted that the
licensee had reported the previous valve failure and considered this a conservative report.
Although the licensee's reportability determination for the most recent failure was
ultimately correct the inspector noted some inconsistencies with the licensee's bases and
the NRC guidance (NUREG 1022) on reportabilty. The licensee acknowledged the
inconsistency and plans to review and revise their reportability procedures as necessary.
The HPCI turbine exhaust valve is required to be tested quarterly; however, the valve was
being tested at a monthly periodicity as a result of previous stroke f ailures, consistent with
the in service test (IST) program requirements. T he inspector found that valve HV-055-
1F072 had four si.nilar f ailures in the last four years. Following each of these failures, the
valve was successfully closed on the tecond attempt af ter re-opening the valve.
Diagnostic testing on tho three most recent failures verified that there was no observable
valve damage and that subsequent diagnostic tests did not indicate a degradation in valve
performance. During the most recent failure, the licensee identified mechanicalinteraction
of valve internal components while performing diagnostic evaluations during the first
attempt to close the valve. The failures and associated corrective actions for valve HV-
0551F072 are as follows:
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March 1994 During routine HPCI system restoration the valve f ailed to fully close.
The root cause was identified to be lack of lubricatinn on the valve
stem. The stem was lubricated and the valve subsequently stroked
successfully.
December 1994 During a scheduleu HPCI system work window this valve experienced
mechanical binding near the full open position when stroked by hand.
The f ailure was attributed to thermal effects (binding). The valve was
placed on increased frequency IST testing (30 day intervals).
May 1995 The torque switch setting was increased to overcome the frictional
forces of internal valve binding exhibited in the December 1994
ovent. The valve was successfully stroked numerous times during
increased frequency IST testing (Dec.1994 to May 1995), subsequent
quarterly testing and HPCI system scheduled maintenance.
September 1937 During application of a HPCI system clearance for a planned outage
window this valve f ailed to fully close. Diagnostic testing did not
identify a root cause and the valve was again placed on IST increased
frequency stroke time testing (30 day intervals).
October 1997 During the monthly increased frequency valva stroke time testing the
valve f ailed to fully close on the first attempt. The valve failed in the
same manor as the September failure. Investigation of this failure did
not identify a root cause. The valve actuator output force was
increased, by adjusting the torque switch, as a precautionary measure
to improve valvo performance. Motor control center (MCC)
components were reviewed to ensure that the additionalload would
not adversely effect other equipment. The valve remained on
increased frequency IST valve stroke time testing,
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December 1997 Diagnostic testing identified that the valve operator motor was
degraded, but operable. Based on the test data the licensee
l concluded that this may have been a contributor but was not the root
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cause of the incomplete valve strokes,
January 1998 During increased frequency IST valvc atroke time testing this valve
f ailed to closed. The valve was reopened and successfully stroked
closed. Diagnostic testing performed during the failed stroks attempt
indicated internal valve binding. Subsequent diagnostic testing
verified there was no internal valve damage which was consistent
with past testing.
The inspector observed the site engineering interdisciplinary review and disposition of the
valvo performance at,d assoc:ated operability issues. This interdisciplinary review team
consisted of the system manager, component experts, engineering supervision, onsite and
off site licensing. The review was thorough with good candid discussions on the required
safety functicos, current licensing basis and technicalissues associated with this valve.
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Although the review was appropriately focused on plant safety, the interdisciplining team
did not adequately consider the compliance with the stoke time specified in technical
specifications. The review concluded that this valve is of minor safety significance, there
was no evidence of valve damage during the past failed attempts to close the valve and it
could be closed successfully on the second attempt. Therefore, engineering was confident
that the valvo would closo and if it did not close on the first attempt then the applicablo TS
would be entered. However, engineering did not recommend any additional or different
measures to improve the reliability of this valve to closo on the first attempt necessary to
ensure the requirod closure time would be met.
The plant operations review committee (PORC) review of this issue considered operational
impacts, including, current operator workarounds, accident progression, and operator
abilities and concluded that these additional operator actions would not adversely burden a
reactor operator. However, the inspectors observed that PORC failed to challenge the
engineering recommendation and aid not fully address compliance with the required stroke
time in light of the repeated f ailures of the valvo to close on the first attempt. In this
review, PORC discussed increasing the valve stroke testing to more frequent interval than
the 30 days specified by the IST program, but concluded that it was not necessary. The
overall recommendations were similar to the sito engineering recommendations discussed
in the above paragraph.
The inspector determined that the licensee did not establish an adequate bases for
operability and f ailed to fully address the required closing time specified in technical
specifications. The inspector questioned the ability of the valve to consistently meet the
required closure timo in light of the valvn p;itormance history coupled with the lack of a
definitive root cause. The concern was discussed with the plant manager.
As a result of the NRC concern, additional engineering evaluations were performed and the
PORC members reconvened to further address the bases for operability. The subsequent
engineering assessment concluded that stroking this valve more frequently than 30 days
would not damage the valve but also that the valve was fully operable in the current
condition. At the conclusion of the management meeting the PORC members determined
that stroking of the HPCI exhaust more frequently than a 30 day interval was acceptable.
Ultimately the licenseo determined that stroking the valve at a more frequent interval would
be prudent and provide the necessary assurance of valve operability. The valve was
declared operable following three successful stroke tests and placed on an increased test
frequency of seven days to ensure reliability of this valve.
The inspector determined that the purpose of the safety evaluation was to review the
impact of delaying further investigation and repairs to the HPCI exhaust valve until the next
scheduled refueling outago and the review of procedure changen being implemented to
address a f ailure of the valve to close on the first attempt. However, this was not an
appropriate vehicle to address the degraded condition of the HPCI exhaust valve sinco a
there was a technical specification requirement for valvo stroke time which was being
impacted by the valves performance. Although the engineering assessment and supporting
safety evaluation provided a strong safety bases for removal of the stroke time requirement
from the technical specifications, the requirements cannot be modified directly or indirectly
using the 10 CFR 50.59 process.
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The HPCI turbine exhaust valve (HV 0551T072)had f ailed five times in the last four
years. Three of the five failures have r>c':urred in the last five months. The inspector was
concerned regarding the adequacy of the corrective actions implemented during those
failures. This issue is unresolved (URI 97-10 06)pending the identification of the root
cause of the valve failures to close on the initial attempt and the subsequent corrective
actions.
c. Concludgna
The engineering assessment and supporting safety evaluation to support operability of the
HPCI exhaust valve was inadequate in that it did not address the valve closure time
requirements. The plant operations review committee (PORC) approved the safety
evaluation, but f alied to challenge the engineering assessment discounting the requirement
for the valve to close the first time to meet the closure time required by technical
specifications in assessing operability, PORC accepted the degraded condition of the valve
without having identified the root cause or evaluating the corrective actions to ensure
future valve reliability and thereby the ability to meet the required closure time.
The use of a safety evaluation to accept the delay in further investigations and testing of
the HPCI exhaust valve, until the next scheduled refueling outage, in effect inappropriately
modified the technical specifications required closing time. The use of the safety
evaluation in addressil.g operability was not necessary nor consistent with NRC guidance
on operability provided in generic letter 91 18.
E2.2 Emeraency Diesel D22 Loss of Control Durina Monthlv Load Test
a. Insnection Sqgng
On January 7, during the monthly load test of D22 EDG the control room operator was
notified by l&C personnel who noticed e change in pitch of the engine as well as the diesel
load at 3700 KW. The control room operator found the D22 EDG running at 2800 KW
and started to lower the load to 2750 KW, The engine load instantly increased to 3700
KW and the operator could not restore the load to normal. The operator secured the EDG
and declared it inoperable. The inspectors reviewed the root cause, corrective actions, and
operability determination for the EDG.
b. Obserygtions and Findinas
The cross current control relay (CCCR) was found in the de energized condition and its
contacts had high resistance. When energized the CCCR allows the EDG droop circuit to
control the loading of the diesel. When the CCCR is de-energized the droop circuit
feedback is removed and the EDG will operate in the isochronous mode (will attempt to
carry all the loads on the bus). The de-energization of this relay resulted in the EDG
loading as it would during an accident. The EDG attempted to carry all the loads on the
bus which was in parallel with the grid but was limited by the fuel rack stops.
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The root cause of the CCCR relay failure was found to be a high resistance en the relay 71n
to socket connections. Oxidation was found at the base of the pins, on the portion not
coated with solder, which caused intermittent contact and allowed the relay to de energize.
Since another EDG was inoperable for planned maintenance the CCCR from that EDG was
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also sent out for analysis, which found similar but less severe oxidation. The CCCR relays
for both EDGs were replaced. At the end of the inspection period the licensee was still
evaluating the cause of the oxidation and possible corrective measures. The inspector
- determined'that although the root cause for this event appears to have been adequately
identified, there was no cause and effect analysis documented and the as found conditions
were not documented in detail in the work order.
PECO inspected areas that could have been over stressed during the overpower event
including the upper and lower piston rings, the connecting rod bearings, and thrust
measurements of both turbo chargers. No excessive wear or damage was identified and
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the turbo charger tole.ances were within specifications. The review of the generator
performance during this overpower condition concluded that the generator sizing was
adequate to support the increase load without degradation.
The inspector also reviewed the maintenance rule (MR) f ailure analysis. The required
function of the EDG is to supply AC power to the appropriate safeguards bus in the event
of a loss of offsite power with and without a coincident loss of coolant accident. For
these conditions the EDG starts with the governor controlin isochronous mode in which
case the CCCR relay is not energized. Since the CCCR relay is not required to energize for
the safety related function of the EDG, this failure would not have prevented EDG from
starting and loading as required by plant analysis. The licensee correctly evaluated this
f ailure to not be a maintenance rule functional f ailure,
c. Conclusions
The organization response to this event was good particularly since another EDG was also
- inoperable for planned maintenance and was competing for the same personnel resources.
, The D22 EDG was returned to an operable status in about two and a half days following a
thorough assessment of the overpower event which including a variety of followup
! inspections and measurements. The root cause analysis of this event was adequate;
however, documentation weaknesses were noted including the as found conditions not
being documented in detail in the work order.
E6 Engineering Organization and Administration
E6.1 Main Safety Relief Valve Commitment Chanae
a. insoection Scoce (71707)
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The inspector reviewed a commitment change regarding the threshold for the licensees
actions related to leaking main safety relief valves (MSRV). In two letters dated October 6,
1995 and March 1,1996, between PECO Energy and the NRC, the licensee committed to
an action plan to address main steam safety relief valve leakage. This commitment was a
result of an inadvertent opening of an MSRV as a result of degradation from prolonged pilot
valve leakage (see Resident inspection Report 50 352/353 95 81).
b. Observations and Findinas
On October 15,1997, the licensee forwarded a letter to the NRC which stated, "the
purpose of this letter is to inform the NRC of a change to the commitment for MSRV
leakage action plan only " The letter discussed the revision of the temperature and leakage
parameter values for monitoring and performance of an operability assessment including
the bases for these changes. An overview of the revised action plan was provided as an
attachment.
PECO submitted the commitment cinange per the process as described in procedure t.R C-
1, exhibit 4. The inspector determined that the specific commitment change
documentation _ identified that implementation of the change was acceptable and that a 10
CFR 50.59 safety evaluation was not required. Normally, the NRC would be notified of the
revised commitment during the next annual summary report; however, PECO elected to
notify the NRC prior to the annual summary report due to the previous sensitivity of the
issue.
The inspector questioned when the revised commitment would be implemented. An MSRV
having an elevated tailpipe temperatore already existed at Unit 2. The inspector noted that
PECO's actions were as addressed using the originally comrnitted strategy. Three months
later, at the end of the inspection period, the inspector noted that PECO had not
implemented the revised methodology to address MSRV leakage. The licensee explained
that the advance letter was to notify the NRC of the upcoming change, and was not
intended to reflect that the change had occurred. PECO plans to implement the MSRV-
commitment change in the near future and consequently will not revise the letter. In
addition, PECO plans to review the procedures and make changes as necessary to ensure
that written communications clearly identify the dates by which commitments are expected
to become effective if not already implemented.
Although the revised methodology appeared technically sound, based on interviews and a
review of the available data, the technical evaluation to support the modification of the
commitment was not well documented. Specifically, the evaluation to support revised
monitoring and operability strategy was not comprehensive in that it did not correlate the
performance data to specific changes in the thresholds values. For example, the
operational data used as the bases for the threshold for performing an operability
assessment wers not delineated. The f ailure to appropriately detail engineering evaluations
creates a vulnerability to subsequent reviews such as plant operations review committee
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assessm:nts. Based on discussion with engineering management the documentation did -
not meet their expectations and would be enhanced in the future for similar evaluations.
The licensee plans to ensure complete and comprehensive evaluation of a change to an
NRC commitment is documented in a single change package.
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c. Conclusions
The licensee appropriately implemented the commitment change process for the main
safety relief valve commitment change. Although the timing of NRC notification for the
change was sooner than required by the process, the letter was misleading in that it
implied that the change had been implemented as of the date of the letter, whereas three
months later at the end of the inspection period the change had not been implemented.
However, no violation of NRC requirements was identified. In addition the engineering
evaluation to support the modification of the commitment was not comprehensive in that it
did not correlate the performance data to specific changes in the thresholds values.
IV. Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
R1.1 Internal Exoosure Assessment
a. Inspection Scone (83750)
The inspector reviewed the licensee's internal exposure assessment program through a
review of positive whole body count measurements and resulting licensee assessments and
exposure record documentation. Calibration of whole body counters and measurement
capability were also reviewed.
b. Observations and Findinas
The inspector determined from a review of approximately 20 positive whole body counts
over the previous 18 month period, that approximately 2/3 of these whole body counts
had significant unidentified peaks with low error associated with them, it was not
apparent that whole body counts indicating unidentified peaks were effectively resolved
and dispositioned by the staff, though all were reviewed.
For example, a June 22,1996 whole body count determined an internal dose of 3.4 mrem,
however, the whole body count had an unknown peak that represented 23% of the total
counts abovs background (not including natural radioactivity). This peak may have been
cobalt 60 and if it had been properly dispositioned, would have added 12.5 mren to the
internal dose assessment for a total of ' mrem instead of 3.4 mrem.
.
Whole body counter Quality Control (QC) checks were performed prior to instrument use
each day. Cesium-137 and cobalt 00 sources were utilized and the detector performance
and trending data were not printed out or otherwise documented. The software program
.provides notification to the whole body counter operator if the QC check falls outside of
three standard deviations of the decay-corrected source activity. -= -- -
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The licensee had appropriate calibrations performed for both Sodium lodido (Nall detector
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whole body counters in October 1997 that utilized appropriate phantom geometry w3 th
National Institute of Standards Technology (NIST) traceable sources. Upon review of the
licensee's 10 CFR 61 waste stream analysis results, the inspector compared the principal
gamma emitter photon energy peaks for each radio nuclide with the whole body counter
peak resolution calibration. Both whole body counters exhibit photon peak resolution of
approximately 61 kev in the 800 kev range. The inspector noted that cobalt 58 and
manganese 54 have principal gamma photons separated by 24 kev, and that according to
the calibration results reviewed, the whole body counters would not be able to accurately
determine these two common radio nuclides. The licensee conducted two separate tests
with medium and high activity smears from the plant that contained significant quantitles
of both cobalt 58 and manganese 54. The whole body counter (Accuscan bed counter)
identified manganese 54, but failed to identify any cobalt 58 from either test. Other
gamma emitters that were identified in the test samples by the chemistry counting
laboratory, were also not detected by the whole body counter (zinc 05, chromium 51, and
iron 59). Approximately 04% total activity of the gamma emitters was not identified by
the whole body counter.
To demonstrate the potential effect, the inspector weighted the percentages of each
gamma-emitting isotope by their Annual Limit for Intake for inhalation and determined that
the whole body counter identified approximatoty 85% of the hypotheticalinternal exposure
from the gamma-omitters. Approximately 15% of the internal exposure was not
represented. Therefore,if the smears taken by the licensee were indicative of the plant
airborne inhalation hazard, the licensee's dose assessments, if based solely on whole body
count measurements, may be approximately 15% low.
The inspector reviewed approximately 20 whole body counts that indicated activity above
background (and natural radioactivity) and noted the same phenomenon. In addition, from
the review of a personnel contamination incident that occurred on August 2,1991
(documented in Section R8.1 of this report), the radio nuclide Cr 51 was the prominent
isotope found in urine samples collected, was detected in nasal smears, and in
contaminated clothing samples, however, none of the whole body counts identified this
radio nuclide. For that case, the licensee utilized the urine bloassay data to calculate the
exposure due to the Cr.51 and added it to the whole body count derived exposure.
The inspector determined that the licensee's program for use of the Nal whole body
counters at Limerick did not appear to have sufficient rigor relative to the disposition and
assessment of uridentified peaks. Further, it was not apparent that the staff was
cognizant of the equipment limitations posed by Sodium-lodide detectors relative to the
effective resolution and identification of all of ine detectable radio nuclides that may be
common to the plant,
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Notwithstanding this weakness, the effectiveness of the contamination control program at
Limerick has made it unnecessary for the licensee to document internal exposures of
workers. Consequently, weakness in this particular area does not currently effect
personnel exposure assessments. The licensee committed to perform further review of this
area to ascertain the adequacy of the equipment, procedures, and personnel training in this
area.
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The licensee utilizes personnel contamination monitors located at the egress from the RCA
and from the station protected area, for detecting the presence of internally deposited radio
nuclidos. The use of these monitors has replaced the use of routine entrance, exit and
annual whole body counting of station personnel. The Eberline PM 7 monitors are gamma
sensitive plastic scintillator detectors that appears to have, based on currently identified
station radio nuclides, the ability to detect approximately 4% of the annuallimit of intake
(All) based on the most restrictive radio nuclide within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of the intake. This
corresponds to on internal exposure screening level of approximately 200 mrom. By
procedure, following a PM 7 alarm, contamination frisking and,if necessary, investigative
whole body counting is performed in order to quantify internal exposures. Regulations
require internal exposure determinations at 10% of an ALI (500 mrom for Limerick Station).
No discrepancies were noted,
c. Conclusion
The radiation protection program controls for preventing internal exposures was effective.
No significant personnel exposures were apparent. However, the whole body
measurement capability appeared to lack sufficient rigor in ssuring that allinternally
deposited redio nuclides, that the whole body counting inv..ument was expected to detect,
were effectively identified and evaluated. It was not apparent that staff were cognizant of
the inherent limitations of the equipment relative to discrete resolution of energy peaks to
offect radio nuclide identification. The licensee acknowledged the inspection finding and
stated their intent to procure a higher resolution whole body counter detector before the
next refueling outage.
R 1.2 Resoiratory Protection
a. Insoection Scoce (83750)
The respiratory protection equipment storage and issue controls were reviewed.
b. Observations and Findinag
The licensee's respirator processing is provided by a vendor service. The licensee has
conducted a vendor QA audit upon initial contracting for this service in 1997. The
radiation protection L.mager (RPM) indicated that periodic audits of this service would be
conducted by the RP group to ensure calibrated leak testing of respiratory protection
equipment is conducted as required. Proper onsite storage and control of respirators and
breathing air bottles was verified, issuance of respiratory protection is controlled through
computer verification of qualifications, which was verified by the inspector. The station
service air and Eagle air compressor (utilized for filling air bottles) air quality had been
tested quarterly and met Grade E quality standards (as defined by the Compressed Gas
Association). Allinspected areas of the respiratory protection program met regulatory
requirements.
c. Conclusions
The respiratory protection program met regulatory requirements.
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R1.3 Countina Laboratory Calibrations
a. Insoection Sjagg (83750)
The inspector reviewed the licensee's air sample counting laboratory instrument calibration
and OC response check program with respect to regulatory requirements and industry
standards. This review consisted of laboratory counting geometry observations, review of
calibration and detector response check documentation, and interviews with applicable
licenses staff,
b. Observations and Findinas
The inspector reviewed the calibration data for two gas flow proportional counters and four
germanium detectors that are utilized for counting air samples as well as chemistry '
samples. The calibration data indicated that appropriate voltage plateaus and counting
efficiencies had been determined utilizing NIST traceable sources following correct
methods. OC response checks for all the above counting instruments were kept up to date
and provided the appropriate trending data of detector performance.
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The inspector reviewed the most recent 10 CFR 61 radio nuclide analysis results for the
- dry active waste-stream, which represents average plant contamination, and therefore,
altborne contamination. Using this information, the inspector determined that
approximately 6.3% of the total activity consisted of non-gamma emitting rsdio nuclides
that were not measurable by the germanium detector counting equipment with respect to
average plant contamination. By reference to 10 CFR 20, Appendix B, the missing activity
would account for approximately 2.7% of Derived Air Concentration (DAC) measurements.
Although this is a relatively low amount, the licensee does not have a criteria for including
non gamma radio nuclides into DAC evaluations. The RPM indicated that this issue would
be reviewed,
c. Conclusion
The air sample counting laboratory provided properly calibrated and reliable sample analysis
services.
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R1.4 Release of Material from Turbine Buildina Roof
lhe licensee began replacing the turbine building and control structure roofs in August
- 1997 and work was in progress at the time of this inspection. The licensee had taken
j numerous core samples and found trace contamination in three samples of the outer rock
L layer from the control structure traf centerline while all other samples did not indicate any
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measurable activity. Approximately 8 drurm of rr cLs were collected from the control .
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structure roof to be shipped to a radwaste pi. . ssing vendo.. All other roof material was
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free released and disposed of in a conventionallocallandflil. The inspector reviewed the
licensee's sampling plans that included 188 core and rock samples and determined that a
good systematic sample plan had been conducted. The inspector reviewed the sensitivity
of sample counting. The licenset utilized the Offsite Dose Calculation Manual (ODCM) to
establish the counting sensitivity at the envirai.mentallower limits of detection (LLDs).
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Selected roof sample analysis results were reviewed and the inspector verified that for the
roof materials released for unrestricted use, no radioactivity was detected in those samples
and they were adequately counted to the environmental LLD sensitivity level as specified in
table 13.4 3 of the OCDM.
R1.5 lanigsentation Calibration
a. Insnection Senpe 183750)
The inspector reviewed the licensee's portable radiation detection instrumentation and
dosimetry calibration program through a review of plant radiation characterization; source
selection and instrument calibration; and instrument calibration method: logy and
instrument calibration records. This review included calibration laboratory observations,
instrutnent calibration record review, and interviews with plant staf f.
b. Observations and Findinas
Through a review of April 1997 in situ gamma scans of plant piping and a review of the
most recent waste stream characterization data, the inspector determined the average
gamma and beta energies at Limerick Station to be 1.2 MeV and 100 kev, respectively.
The inspector reviewed the instrument calibration sources and determined that the Tc 99
beta source was appropriate for the beta spectrum in the plant, however, the Cs 137
source, at 662 kev, was a calibration source that was almost half of the average gamma
energy found in the plant. The inspector determined that the licensee's calibration '
methodology did not correct for this difference in gamma energy. By reference to
instrument vendor information for two of the most common portable radiation detection
instruments utilized at Limerick (Eberline RO 2, E 530), the response in the field would be
expected to be 2 5% higher than actual. Though this is a minor error in the conservative
direction, the inspector noted that the licensee's process compensated for other errore,
such es temnerature and pressure, that had a more minor effect on instrument accuracy.
Other minor discrepancies included:
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Source to-instrument distances needed for calibration were not determined prior to
source calibration. Consequently, during instrument calibration, dose rate values
needed to be interpolated between values, which may introduce a minor, but
unnecessary, calibration error.
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The vendor software program that provides decay corrected source calibration
tables of dose rate versus distance for each source attenuator was not inputted
with the current NIST traceable source calibration values. Accordingly, a minor
error may be included into the instrument calibration target values.
The RPM indicated that these source calibration discrepancies would be reviewed and
action taken as necessary to assuro the accuracy of the RP instrument calibration program.
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The inspector reviewed calibration documentation records for selected RP instruments that
were available for issue and determined that all were properly calibrated within the required
time period. The inspector also verified proper locked storage of calibration sources and
that the source calibrator interlocks were in proper operating condition to prevent
Ir. advertent exposure to personnel.
A review of the Rados Rad 51 electronic dosimeter calibrations and National Voluntary
Laboratory Accreditation Program (NVLAP) testing results indicated appropriate calibration
techniques and calibration frequencies were met and that the electronic dosimeter
demonstrates a positive 11% bias in the normal gamma energy range of the plant and a
positive 8% blos for high energy gammas associated with N 16 decay that might be
enn intered during personnel entries at power. The positive bias is desirable to ensure
conservatism in the exposure control program relative to later TLD processing and record
exposure determinations No discrepancies were noted.
A review of TLD processing quality controls were found to be excellent and well managed.
Af ter changing to (ICN), as a new TLD processing vendor in early 1997, quality control
badge processing results indicated combined bias and standard deviation values
approaching NVLAP limits. Both Peach Bottom and Limerick RP staffs actively pursued the
issue with ICN, which resulted in new Thermoluminescent Dosimeter (TLD) calibration
factors for e..;h TLD and resulting improved performance. Each calendar quarter Limerick
and Peach Bottom alternate sending spiked quality control TLD badges for testing of the
vendor's TLD processing capability. The TLD vendor maintains current NVLAP
accreditation as required,
c. Conclusion
The inspector determined that the licensee's radiation protection calibration program
utilized sound principles, however, minor discrepancies in the instrument calibration
process had the potential to introduce unnecessary errors. Notwithstanding, the
instrument calibration area was determined to be adequate. The TLD program oversight
was very effective in enhancing the accuracy of vendor TLD processing results,
a R2 Status of RP&C facilities and Equipment
During this inspection, the inspector conducted numerous tours of the plant during
operating conditions. The licensee made frequent use of radiation dose rate postings and
posting sources of radiation postings in applicable areas, which were excellent practices.
All radiological postings and locked areas mot regulatory requirements and areas were
generally clear of unnecessary equipment, wellilluminated and generally free of safety
hazards. One exception, an abandoned in place post accident sample skid, was noted in
Unit 1 Reactor Building, Room 501.
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R4 Staff Knowledge and Performance in RP&C
R4,1 Exoosure Discrenancy Reports
a. Insoection Scope 183750)
The inspector reviewed the disposition of external exposure discrepancies for the third
quarter of 1997 that indicated exposure differences between Individual's quarterly TLD
results and quarterly electronic dosimeter (ED) exposure results,
b. Observations and Findinas
The inspector observed that there were a large proportion of exposure discrepancies
derived from individuals making roof repairs from the turbine and control structure roofs.
Upon review of several of the roofers exposure discrepancy reports, the inspector observed
that all of them showed higher ED results, i.e., between 27% and 111% greater than TLD
results for the same time period, in all cases, the personnel exposures were well below
regulatory limits.
All of the subject exposure discrepancy reports assigned the lower TLD results rather then-
the more conservative decision to assign the electronic dosimeter results in the personnel
exposure records. The reasons stated in the individuals' personnel exposure records were
nonspecific, but indicated that degraded N 16 gamma photons and electro-magnetic field
(EMF) interference could have caused the discrepancy and that surveys of the roof
confirmed the TLD results.
Expecting that EMF radiation may be responsible, the licensee conducted a EMF survey but
did not detect any EMF fields. The inspector's review of the ED calibration testing
indicated a relatively accurate response in the N 16 gamma energy range. At the time of
the inspection, the licensee was still attempting to test the EDs response to cellular phone
broadcast interference, but no evidence had been uncovered that would explain the
exposure discrepancy results for the roofers. -
The inspector identified that this area will be followed to ensure the adequacy of the
licensee's process for evaluating personnel dosimeter result discrepancies.
(IFl 50 352,353/9710 07).
c. Conclusion
Several exposure discrepancies between T! D and electronic dosimeter quarterty results
were resolved but the adequacy of their disposition requires further review.
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R5 Staff Training and Qualification in RP&C
RS.1 RP Technicir.n Trainina and Qualifications
a. Insoection Scoce (83750)
The inspector reviewed the RP technician training program, reviewed selected RP
technician qualifications with respect to TS 6.3 requirements, and reviewed the control of
RP work task assignments to only qualified individuals,
b. Observattens and Findinas
During 1997 there were three individuals that completed the initial qualifications for Level 11
(senior) HP technician. Currently all RP technicians at Limerick Station arn fully qualified
Level ll RP technicians. The inspector reviewed the initial RP technician training prngram
and determined that it was comprehensive including sufficient classroom study and job
performance evaluations prior to qualifications.
The inspector determined that the licensee had an adequate process for reviewing staff
qualification signoffs prior to assigning staff duties. At the principal radiological controlled
area (RCA) access point (41 line), an RP technician qualification matrix is printed out
weekly and made avaliable for first line supervisor use in assigning only qualified staff to
perform tasks. By licensee procedure (TO C 7), it is the supervisor's responsibility to
ensure staff are not assigned to perform work they are not qualified to perform.
The Radiation Protection (RP) technician continut... training was found to be adequately
implemented, in February 1997 the licensee administered an RP fundamentals examination
to 36 permanent RP technicians. The results were poor. The licensee provided remedial
training and testing and the results improved to an adequate level. The licensee is aware
of the RP fundamentals training weakness and is working to improve the level of RP
technician knowledge in this area,
c. Concluiisnt
The RP training program was adequate. The licensee has self identified a weakness in the
RP fundamentals training provided to RP technicians in the continuing training program,
and has made some progress in addressing this concern Currently, all RP technicians are
fully qualified senior technicians and an active continuing training program and qualification
tracking program is in place.
RS.2 Advanced Radiation Worker Pro 2Lan]
a. Inuction Scooe (83750)
The inspector reviewed the licensee's advanced radiation worker procedure and selected
survey results with respect to Technical Specification 6.3.1 requirements.
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b. Observations and Findinas
The licensee has established a program to qualify experienced radiation workers on certain
se'ected RP tasks traditionally performed by RP technicians. Procedure HP C 111 requires
the advanced radiation worker (ARW) candidates to complete an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> class and
successfully pass a job performance measure evaluation to qualify for task specific RP
technician duties. The procedure limits the radiological conditions to less than high
radiation areas and less than 50,000 dpm/100cm' contamination levels. The procedure
indicates that specific task qualifications can only be added with the approval of the RPM.
The inspector reviewed recent surveys, completed by several advanced radiation workers
and observed that several radwaste technicians that were appropriately qualified ARWs,
had surveyed contanination areas after decontaminativn and based on their surveys,
removed postings and released the areas as clean areas without any RP technician
supervision or verification, it was not apparent to the inspector, wheth7r the ARWs were
within the limited specific task qualification or whether they were exercising broader RP
technician skills of judgement as to when an area of the plant should be deposted. Further
review of the ARW program is needed to properly evaluate whether a violation of staff
qualification requirements has occurred. This is an unresolved item (URI 9710-08),
c. Conclusions
The licensee has limited procedural controls over the scope of the advanced radiation
worker program. Some survey and contamination area control activities have been
performert by the advanced radiation workers that involved evaluation and judgement
determinations without qualified RP technician supervision. Further investigation in the
advanced radiation worker training and performance is nneded to determine whether a
violailon of TS 6.3.1 has occurred.
RS.3 Health Physics Personnel Qualification
a. Insoection Scone
The inspector reviewed the process and controls associated with personnel qualifications
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with a specific focus on the dosimetry clerk position, in addition, the implementation of
i controls for the use of unqualified personnel were evaluated,
b. Qblervations and Findinas
The individual selected for review was found to be fully qualified for the position of
dosimetry clerk. However, during the review the inspector identified that the individual had
- performed the duties of dosimetry clerk prior to completing qualification for all tasks. The
job functions are typically broken down to a task or series of tasks for the purpose of
implementing qualifications. Qualification includes a classroom training session and a
subsequent demonstration of task competency during completion of a job performance
measure (JPMs). The individualin question had completed all required classroom training
but had not performed the required JPMs prior to performing the duties of a dosimetry
clerk,
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Technical specifications requires that the unit staff training meet or exceed the standards
of ANSI /ANS 3.1 1978. The dosimetry clerk position is not specifically addressed in this
standard. However, the licensee had establishea a training and qualification program for
this positions that is accredited by the Institute of Nuclear Power. The licensee's program
has provisions for the use of unqualified personnel to perform tasks provided that they are
appropriately supervised. Procedure TQ-C 7, "On The-Job Training and Qualification,"
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requires that unqualified personnel may only perform tasks under the direct, continual
observation of either a qualified worker or line supervision.
The primary functions of the dosimetry clerk include operation of the whole body counters
and an evoluation of the results, performance of respirator fit tests, and issuance of
dosimetry. The inspector reviewed the logs and documentation of whole body scans
performed by the individual that was not qualified and found that generally there was
evidence that a qualified person performed the whole body count reviews or provided
supervision to the unqualified individual. Specifically for the sample of documentation
reviewed, either a qualified individual counter signed the log sheets or signed the whole
body scan results as the reviewer. However,in the case of the other dosimetry clerk tasks
there was no evidence of direct supervision. For example, the dosimetry issue log does
not contain countersigned e les indicating that the task was supervised.
The most significance of the dosimetry clerk tasks is reviewing of the whole body scans
for anomalies. The rest of the tasks were generally found to be of low complexity and low
consequence if improperly performed. For example, operation of the respirator fit
equipment involve operation of a computer driven test routine which automatically prompts
the actions required by the person being tested. An incorrectly performed operational
check or test routine would result in a test f ailure, in the case of issuing dosimetry, this
task is administrative in nature and provisions are in place which would likely identify if
dosimetry issued was not recorded correctly. -
During the records review the inspector identified one instance in which there was no
signature for reviewing the results of a whole body count. Following discussion with the
inspector the licensee plans to perform a more comprehensive sample of personnel records
to determine if a more wlae spread problem exists. The licensee plans to sample a
minimum of 100 files containing whole body counts to confirm the required reviews were
performed and determ;ne any other administrative errors exist.
c. Conclusions
An unqualified person had been assigned to perform tasks which require formal
qualification. Generally, there was evidence of direct supervision for the more critical tasks
performed by unqualified individual such as the performance and evaluation of whole body
counts, However, for administrative tasks, generally there was no recorded evidence of
direct supervision as required by the licensees training and qualification procedures.
Although, the practice of using unqualified and unsupervised personnelis inconsistent with
the licensee's procedure, this was determined not to be a violation of regulatory
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requirements since the position and job functions are not specifically addressed through the
technical specifi .:on requirements for tne training of plant staff. However, the failure of
the licensee to appropriately control the use of unqualified personnelis of concern since
the same procedure control are used to address positions which have specific training
requirements,
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R7 Quality Assurance in RP&C Activities
a. Insoection Scope (83750)
The inspector reviewed the licensee's quality assurance oversite of the RP program
consisting of a review of licensee documents of a recent GA audit, recent QC surveillance,
and RP self antossments,
b'. Observations and Findinas
The inspector reviewed the report of a Quality Division audit of the RP program that was
conducted in March of 1996. The report was detailed and comprehensive. One minor
radiation work permit (RWP) discrepency and some additional training was needed for
outage contractors was reported. The inspector noted that Limerick and Peach Bottom
Stations provide technical specialists to evaluate each other, but no outside PECO Energy
technical specialists were utilized in the independent program reviews.
Since March 1997, there have 16 OC surveillance of the RP program areas that indicated a
wide scope of program review and oversight.
The RP Section provides its own self assessment reviews and the inspector reviewed the .
September 30,1997," Annual Self Assessment of the RP Section," and found it to
represent all of the radiation protection functional areas t the Station and included many
recommendations. This appeared to be a valuable program review.
Other.RP Section program reports were also reviewed by the inspector included the
Radiation Protection Integrated Program Review and the Limerick Unit 2 fourth Refueling
Outage Report.
c. Conclusions
Oversight of the RP program consisted of independent and self assessments that generally
provided for effective insights and recommendations for program improvements,
notwithstanding the minor weaknesses in the instrument calibration and bioassay
measurement programs that were noted by the inspector.
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R8 Miscellaneous RP&C lasues
R8.1 Dose Assessment Review of an Auaust 2,1991 Contamtriction incident
The inspector reviewed a spent RWCU resin personnel contamination incident that
occurred on August 2,1991, where three individuals were contaminated. After repeated
decontamination, persistent skin contamination remained on the extremities of the
individuals. Multiple whole body counts and urine samples were taken and outside
consultants were involved to provide a comprehensive review of bloassay data and to
assess the radiation exposures to the affected individuals. Bioastny rneasurements
continued until August 9,1991, when the contamination levels dropped to below threshold
values for all affected individuals. The highest exposed individual was calculated to have
received 150 mrom to the skin of the right forearm due to the event. Based on
radiochemicallaboratory analysis of several urine samples,3.5 MPC hours was calculated
due to internal exposure. The inspector reviewed the licensee's exposure records and
verified that for each of the three individuale, the additional skin of the extremities
exposure was recordcd, however, no internal exposures were recorded because they were
all below procedural and regulatory rucording requirements, in 1991, the regulatory limits
for the skin of the extremities was 18750 mrom per quarter and the internal exposure
racording requirements were greater than 40 MPC hours per seven consecutive days and a
limit of 520 MPC hours per quarter. Based on the inspector's' review, the licensee
provided a comprehensive dole study related to the August 2,1991 incident; accurately
represented the personnel exposures; and was appropriately documented in the individuals'
exposure records.
P4 Staff Knowledge and Performance in EP
a. inspection Scone 182701)
Following an Alert emergency notification or above, the licensee's Emergency Responso
Procedure (ERP) 6001, Health Physics Team, Step 3.1, states that six Health Physica (HP)
technicians must be onsite within a half hour and six more within 60 minutes. Following
the October 9,1997 Alert incident, the HP Team Leader identified that he had difficulty in
locating 12 qualified HP Technicians and the timeliness of their response was not
acceptable. The inspector assessed the licensee's review of these concerns to determine
the adequacy of their self assessment and corrective actions.
b. Observations and Findinas
The licensee identified three concerns regarding HP emergency response staffing: (1)
untimely emergency notification to the HP staff; (2) not staffing the required HP Technician
positions in a timely manner; and (3) unavailability of qualified technhians.
With the exception of the HP Team Leader, the HP technicia.is are not included in the
emergency automated dialer callout system and are called by the on-shif t technicians
following direction from the Team Leader. The first available individual was not contacted
until 12:08 a.m., approximately 38 minutes af ter the ERO was notified by pagers. The
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inspector reviewed all the sign in logs and determined that the licensee diu not meet the
commitments made in ERP-6001 as stated above. The licensee stated that as a result of
this issue they are planning to add the HP technicians to the automated dialer callout
syttom to ensure an immediate and timely response.
HP technician availat'ility was diminished because the licensee had several technicians
working at Peach Bottom to assist in their refuel outage. The Radiation Protection
Manager is currently working with Peach Bottom management to revise the refuel outage
policy to ensure that there will always be an adequate number of HPs available to meet
their emergency response commitments. Also, a tracking system is being developed to
track all HPs as to whe e they can be located during off-hours.
The inspector reviewed Procedures, NSC 1.2, HP Technician ll Training; LEPP-9500,
Emergency Preparedness Training Plan and training records of the individuals that
responded to the Alert event and determined that their EP training was currer.t. However,
the :nspector noted that three of the HP 11 Technicians did not appear to have completed
all the Job Performance Measures (JPMs) tasks ac required by HP Procedure NSC 1.2,
Section 7.2.2, which states " Emergency Preparedness Training is developed and
conducted by the Site Emergency preparedness organization and is provided upon
completion of HP Technician il Qualifications." After further review of additional training
procedures, the licensee was able to adequately demonstrate that the pertinent JPMs
related to emergency response had been completed by the three individuals. However, the
licensee recogniud that Procedure NSC-1,2 was ambiguously written and clarity and
consistency was needed between HP training qualification procedures and the Emergency
Preparedness training and qualifications plan,
c. CgprJhigi9D
Although, the licensee was not in full compliance with Procedure ERP-000-1, Health
Physics Team, they were proactive in identifying the issues and their corrective actions are
adequate for preventing recurrence. The inspector also noted that these issues were not
identified in previous exercises or drills because the licensee had typically conducted their
exercises during working hours in which HP technicians were onsite and available for
immediate response. This non-repetitive, licensee identified and corrected violation is being
treated as a Nnn Cited Violation inlCV 50 352,353/97-10-09), consistent with Section
Vll.B.1 of the NRC Enforcement Policy.
V. Management Meetingt
X1 Exit Meeting Summary
The inspector presented the inspection results to members of plant management at the
conclusion of the inspection on January 28,199 . 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.
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X2 Review of UFSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the 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 apolicable portions of the UFSAR that
related to the areas inspected. The inspectors verified that the UFSAR wording was
consistent with the observed plant practices, procedures and/or parameters.
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: kant Support Activities
IP 83750: Occupation :l Radiation Exposure
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 Or.-cating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
Qoened
NOV 50 352,353/97-10-01 Operations Log Did Not Accurately Reflect Conditions in
the Plant. (Lation O2.1)
NOV 50 352,353/97-10-02 Adequate Musures Not Established to Assure Design
Requirements were Adeqth tely Maintained During HCU
On-line Maintenance. (Sec' in M1.4)
NOV 50 352,353/97-10-03 Inadequate implementation af Locked-Valve Controls.
(Section M8.1)
URI 50 352,353/97-10-04 Mis wired Valve Breaker Circuit and Associated
Drawing issues. (Section E1.1)
URI 50 352,353/97-10-05 Inadequate Testing of Valve Breakers. (Section E1.1)
URI 50-352,353/97-10-06 Unit 1 High Pressure Coolant injection (HPCI) Turbine
Exhaust Valve Failure. (Section E2.1)
IFl 50-352,353/97-10-07 Resolution of non conservative exposure determinations
between TLD and electronic dosimeter results. (Section
R4.1)
URI 50 352,33/97-10-08 Datermine whether advanced radiation workers that
survey and release contamination areas should be
qual!fied RP technicians. (Section RS.2)
NCV 50 ?S2,353/97-10-09 Difficulty in Locating 12 Qualified HP Technicians and
the Timeliness of Their response During the October 9,
1997 Alert incident. (Section P4)
Closed
LER 1-97-011 Unit One High Pressure Coolant injection (HPCI) Turbine
Exhaust Valve Failure (E2.1)
URI 97-03-01 Performance of Reactor Enclosure Secondary
Containment Integrity Verification. (Section M8.1)
Discussed
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LIST OF ACRONYMS USED
ALARA As low as is reasonably achievable
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AR Action Request
J AWR Advanced Radiation Worker
g CFR Code of Federal Regulations
W- CRS Control Room Supervisor
DAC Derived Air Concentration
ED Electronic dosimeter
EDG Emergency Diesel Generator
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ERO Emergency Response Organization
E ERP Emergency Response Procedure
g EO Equipment Operator
R- ESF Engineered Safety Feature
FIT Focused improvement Team
FP Fire Protection
HCU Hydraulic Control Units
HEPA High Efficiency Particulate
E HPCI High Pressure Coolant Injection
] IFl
IR
Inspection Follow up Item
inspection Report
LCO Limiting Condition For Operation
LER Licensee Event Report
LGS Limerick Generating Station
Nal Sodium-lodido
NCR Non-Conformance Report
NCV Non Cited Violation
NED Nuclear Engineering Department
NIST National Institute of Standards Technology
NMD Nucleai Maintenance Division
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NRB Nuclear Review Coard
NRC Nuclear Regulatory Commission
NUPIC Nuclear Procurement issues Committee
NVLAP National Voluntary Laboratory Accreditation Program
ODCM Offsite Dose Calculation Manual
PCIV Primary Containment Isolation Valves
PDR Public Docket Room
PEP Performance Enhancement Process
PORC Plant Operations Review Committee
QA Quality Assurance
QC Quality Control
RCA Radiological controlled area
RCIC Reactor Core isolation Cooling
RMS Radiation Monitoring System
RP&C Radiological Protection and Chemistry
RP Radiation Protection
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RPM Radiation Protection Manager
RWCU Reactor Water Clean-up j
RWP Radiation Work Permit
SGTS Standby Gas Treatment System
SSPV Scram Solenoid Pilot Valve
ST Surveillance Test
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TLD Thermoluminescent dosimeter
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved item
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VIO Violation