ML20137E567
| ML20137E567 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 03/18/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20137E556 | List: |
| References | |
| 50-239-97-01, 50-239-97-1, NUDOCS 9703280032 | |
| Download: ML20137E567 (48) | |
See also: IR 05000293/1997001
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Enclosure 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
1.icense No.
Report No.
97-01
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Docket No.
50-293
Licensee:
Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
Facility:
Pilgrim Nuclear Power Station
inspection Period:
January 12,1997 - March 2,1997
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Inspectors:
R. Laura, Senior Resident inspector
8. Korona, Resident inspector
R. Arrighi, Millstone 3 Resident inspector
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J. Noggle, Radiological Controls inspector
G. Smith, Security inspector
Z. Abdullahi, NRR Intern (Training)
S. Dennis, DRS Examiner
J. Kudrich, NRR
R. Elliot, NRR
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Approved by:
R. Conte, Chief
Reactor Projects Branch No. 5
Divisio.i of Reactor Projects
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9703280032 970318
ADOCK 05000293
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EXECUTIVE SUMMARY
Pilgrim Nuclear Power Station
NRC Inspection Report 50-293/97-01
This integrated inspection included aspects of licensee operations, engineering, maintenance,
and plant support. The report covers resident inspection for the period of January 12 through
March 2,1997. Included in this report were feeders from Region I specialist inspectors in tha
safeguards and radiation safety groups.
Operations: An improved control room environment with less traffic was observed during
RFO11 due to relocation of the control room annex from the control room to the O&M building.
Additionally, members of the operations department had significantly less production
responsibilities due to organizational changes implemented prior to the start of RFO11 which
was a direct lessons learned from RFO10 and peer visits to other nuclear facilities. Lastly, the
plant manager convened meetings prior to the start of RFO11 with all plant personnel that
clearly emphasized management's expectations on following procedures by using key examples.
(Section 1.01.1)
Operators responded well overall to a difficult FRV malfunction by initiating a manual reactor scram prior to any automatic actions occurring. Operctor actions stabilized plant conditions
without any automatic core injection or lifting of the code safety valves. After the first phase
of the event, the operating crew notified outage management personnel but did not consider
notifying operations department management or engineering personnel before recommencing
the shutdown. One violation (VIO 293/97-01-01 [ example 1]) of the abnormal procedure was
identified involving the practice of cycling feed pumps on/off to maintain vessellevel in the
normal band to allow an emergency entry into the condenser bay to manually verify closure tho
"B" FRV. During operator interviews, an apparent inconsistency between the simulator and
plant was identified involving the effects of shrink / swell in vessel water level. Also, instances
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of weak communications were observed during the event. (Section 1.02.1)
The spiral, full core reactor fuel offload was completed in a controlled manner with effective
BECo oversight of contract fuel handlers and no dropping or banging of fuel bundles. Fuel
movement was appropriately stopped to repair the refueling mast air line take-up reel spring.
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Fuel bundle gas sipping, inspection and reconstitution activities were performed using approved
procedures. Quality assurance and operations department management oversight was evident.
One equipment problem was identified near the end of the fuel offload process with the "C",
SRM which operations personnel responded to adequately. Changes in the operating modes of
augmented spent fuel pool cooling were well controlled. (Section 1.02.2)
The use of plastic lock seals for locked valves in high temperature systems resulted in the NRC
identification of a melted locking device on valve 1301-36 and a procedural adherence violation
(VIO 293/97-01-01 [ example 2]). This was a repeat finding since BELo quality assurance
personnel identified a similar concern in January 1995. Operations department management
acknowledged that this violation resulted directly from adverse operator human performance by
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not following procedure 8.C.13. (Section 1.04.1)
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Maintenance: Major RFO11 work activities progressed well. During the work on the "B"
RBCCW heat exchanger and the troubleshooting on the "A" FRV, the use of new tools (i.e.,
tube plug hydraulic installation tool and Keithly tester) and technology (air operated valve
diagnostics) was considered a strength. Workers were noted to be experienced and stopped
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when adverse conditions were identified to obtain proper corrective actions. (Section ll.M1.1)
The refueling floor maintenance crew performed well during reactor vessel disassembly
activities with effective refueling flor management ovessight. Equipment problems were
experienced with the new style reactor stud tensioners that resulted in some additional radiation
exposure to werk crew in the cavity. The new style stud tensioners did not work properly
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during RFO10 aither. After installing the old stud tensioners on the head carousel, the refueling
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crew demonstrated excellent teamwork while removing the reactor head stud nuts. Favorable
radiological conditions in the cavity, which resulted from decontamination efforts at the end of
RFO10, allowed for easy access when detensioning and removing the reactor vessel head stud
nuts. (Section ll.M6.1)
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The failure to schedule the standby switchyard battery performance test in accordance with TS
requirements. The failure to establish the proper surveillance interval for the standby
switchyard battery is a violation (VIO 293/97-01-07. [ example 1]) of 10 CFR 50 Appendix B,
Criterion XVI, Corrective Action. (Section ll.M8.1)
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Enaineerina: Three longstanding degraded equipment conditions (i.e., control rod bottom lights,
RWCU letdown controller, and MO-220-3) came into effect during the February 15,1997 post
scram recovery. These conditions were adverse to quality and required operators to take
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compensatory actions complicating the post scram recovery with the MSIVs closed due to a
Group 1 isolation. These conditions were in violation (VIO 293/97-01-02 [ example 2] of 10 CFR Part 50, Appendix B, which requires timely and effective corrective actions. Further, the
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existence of the these worloarounds indicates a weakness in the effectiveness of the interface
between operations and engineering. (Section Ill.E2.1)
The identification of an uniatched jet pump no.11 gate, by a BECo engineer prior to the outage,
while viewing videotape, and subsequent incorporation into the RF911 for repair was an
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example of excellent problem identification and correction. Engineers filled various outage
positions supporting various work teams or production roles. Installation of the new larger
ECCS suction strainers into the torus to increase the margin to cloggi4 J reflected a timely
safety initiative. NRC review determined that the past reliance on the use of containment
overpressure in the ECCS analysis was an unreviewed safety question (UNR 293/97-01-03).
Credit for a small amount of containment overpressure will still be needed due to the new and
more stringent design assumptions. BECo submitted a licensing basis change to NRR for review
and approval for the use of overpressure. (Section Ill.E4.1)
Plant Sucoort
in completing corrective actions for a 10 CFR 70.51(b)(1) SNM record violation, additional SNM
material was found undocumented. This was considered a follow-up action to the original NRC-
issued notice of violation. (Section IV.R8.1)
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In response to an unexpected and unprecedented jump in drywell dose rates, senior
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management demonstrated superior support for the station's ALARA efforts that resulted in
commitments for both depleted zine oxide injection and the chemical decontamination of
recirculation and RHR piping systems. The results of these actions are estimated to reduce the
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next refueling cutage exposures by one-half. The licensee has been increasing attention t"
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identify and employ initiatives to reduce dose rates in the station. (Section IV.R1.1)
Three facility modifications involving RCA access have recently been completed, which directly
addressed some chronic contamination control and RCA entry problems by streamlining the
process and enlarging capacity. (Section IV.R2.1)
An effective security program was maintained. The corrective actions associated with two
previously identified items related to failure to audit the Access Authorization program within
the prescribed time period and the failure to audit contractor self-screening programs annually
were reviewed and closed. However, the inspector follow-up item, related to marginally
effective assessment aids, will remain open pending installation of new pan, tilt and zoom
closed circuit television cameras. (Section IV.S1)
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Management support of security activities was evident by upgrades in the communications
system, including the installation of new base radio stations in both alarm stations and the
installation of new mobile radios in the two new security vehicles, the acquisition and
insta!Iation of four new security sector post enclosures, and the training of all security
supervisors as first responders for station medical emergencies. (Section IV.S6.1)
Protected area detection equipment satisfied the NRC-approved Physical Security Plan (the Plan)
commitments and security equipment testing was being performed as required in the Plan.
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Maintenance of security equipment was being performed in a timely manner as evidenced by
minimal compensatory posting associated with security equipment repairs. Based on
observatior.s and discussions with security officers, the inspector determined that they
possesseri the requisite knowledge to carry out their assigned duties and that the training -
program was effective. As an addition to the inspection, the UFSAR initiative, Section 5.3.4 of
the Plan, titled " Package and Vehicle Access" was reviewed. The inspector determined, based
on discussions with security supervision, procedural reviews, and observations, that vehicles
were being searched and controlled prior to entry into the protected area as described in the
Plan and applicable procedures. (Section IV.S)
Preparations for RFO11 in terms of fire-treated scaffold construction material and combustion
loading were in accordance with approved procedures. Observed firewatches were
continuously posted or pericrmed hourly rounds, as required. (Section IV.F1.1)
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TABLE OF CONTENTS
l . O P E R AT I O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
O1
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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01.1 G e ne ral C om m e nts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
02
Operational Status of Facilities and Equipment
2
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02.1 (Open) VIO 97-01-01: Manual Reactor Scram . . . . . . . . . . . . . . . . . .
2
O2.2 Operational Refueling Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
04
Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
04.1 (Open) VIO 97-01-01: Broken Locking Device For Valve 1301-36 ....
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l l . M AI NT E N A N C E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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M1
Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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M 1.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . .
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M6
Maintenance Organization and Administration . . . . . . . . . . . . . . . . . . . . . .
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M6.1 Refueling Floor Maintenance Activities . . . . . . . . . . . . . . . . . . . . . .
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M8
Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
M8.1 (Closed) LER 50-293/97-01; Missed Technical Specification
Surveillance Test for the Standby Switchyard Battery
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111. E N G I N E E R I N G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E2
Engineering Support of Facilities and Equipment
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E2.1 Operator Work-Around Conditions . . . . . . . . . . . . . . . . . . . . . . . . .
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E4
Engineering Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . .
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E4.1 Engineering RFO11 Involvement
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IV. PL A NT S U PPO RT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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R1
Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . . . .
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R1.1 As Low As is Reasonably Achievable (ALARA)
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R2
Status of RP&C facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . .
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R7
Quality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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R8
Miscellaneous RP&C issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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R8.1 (Closed) Violation 50-293/95-09-03: Special Nuclear Material
Controls
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R8.2 (Closed) Violation 50-293/96-02-03: Calibration Source Locking
D e vi c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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R8.3 (Closed) Violation 50-293/96-02-04: Radioactive Material Controls . .
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R8.4 Updated Final Safety Analysis Report (UFSAR)
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S1
Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . . . .
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S2
Status of Security Facilities and Equipment
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S2.1 Protected Area Detection Aids . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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S2.2 Alarm Stations and Communications
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S2.3 Testing, Maintenance and Compensatory Measures . . . . . . . . . . . . .
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Security and Safeguards Staff Training and Qualification . . . . . . . . . . . . . .
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Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . .
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f.7
Quality Assurance in Security and Safeguards Activities
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S7.1 Effectiveness of Management Controls . . . . . . . . . . . . . . . . . . . . . .
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S.8
Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . . . . . . . . .
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F1
Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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F1.1
Fire Protection Controls in Preparation for the
Refueling Outage
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V. MANAGEMENT MEETING 3
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X1
Exit Me eting Sum m ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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X4
Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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REPORT DETAILS
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Summarv of Plant Status
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Pilgrim Nuclear Power Station (PNPS) began the period returning power to 100 percent
' following a final feedwater temperature reduction. Operators returned the unit to approximately
100 percent rated power at 1100 on January 12. Reactor power gradually coasted down due
to end-of-cycle conditions. On February 15, operators commenced shutdown of the reactor to
facilitate plant conditions for refueling outage 11 (RFO11). At 22% reactor power with the unit
still on-line, operators manually scrammed the plant due to problems with the feedwater
regulating valves. Operators notified (Event Number 31793) the NRC headquarters operations
officer at 01:56 pursuant to 10 CFR 50.72(b)(2)(ii) for RPS and ESF actuations. Several
minutes after the scram, an automatic primary containment isolation resulted in the closure of
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the main steam isolation valves (MSIVs) due to a " swell" in reactor vessel water level. At the
time of the event, the NRC senior resident inspector was in the control room and notified NRC
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Region I management of the event. Operators lowered reactor coolant temperature less than
212 degrees Fahrenheit to enter Cold Shutdown on February 15. RFO11 commenced with a
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scheduled duration of 39 days. Two major emergent items added to the outage scope included
installation of new ECCS suction strainers in the torus and the conduct of a recirculation loop
chemical decontamination to lower dwa dose rates.The refueling crew detensioned and
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removed the reactor vessel head, rd ihr 1 removed the dryer and steam separator. A full core
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effload of reactor fuel into the spent luel pool was completed on February 24. At the end of
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the inspection period, the core remained offloaded with chemical decontamination of the reactor
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recirculation piping in progress.
On January 7,1997, security personnel identified an undeclared handgun during a vehicle
inspection. BECo made a formal notification to the NRC operations officer pursuant to 10 CFR 73.73(b). The inspector reviewed this event, interviewed the security manager and discusaed
the corrective actions with Region I security specialists. The incident was idenutied and
handled properly by the security guards. Additionally, BECo made another formal NRC
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notification pursuant to 10 CFR 70.52(b) End 20.2201(a)(1)(ii) on January 20,1997 concerning
the results of the physical audit of the special nuclear material (SNM) stored in the spent fuel
pool.Section IV.R8.1 of this report provides further details and assessment of this issue.
l. OPERATIONS
01
Conduct of Operations'
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant
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operations. In general, the conduct of operations was professiona! and safety conscious.
During tours of the control room, the inspectors discussed any observed alarms with the
operators and verified that they were aware of any lit alarms and the reasons for them. Any
anomalies noted during tours were discussed with the nuclear watch engineer (NWE). A review
Topical headings such as )1, M8, etc., are used in accordance with the NRC Standardized
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reactor inspection report outline. Individual reports are not e).pected to adress all outline
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topics.
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of operator overtime for November 1996 to January 1997 found the work hours were
consistent with the limitations of procedure 1.3.67, Control of Overtime, and NRC Generic Letter 82-12, Nuclear Power Plant Staff Working Hours. Required approvals for overtime were
completed prior to the work. Some improvement was noticed in the effectiveness of the shift
turnover briefings as evidenced by more interaction between the reactor operators and senior
reactor op.trators.
During RFO11 lead reactor operators were assigned on each shif t to coordinate activities
between management and bargaining unit personnel. An improved control room environment
was clearly evident during RFO11 as compared to RFO10 due to the relocation of the control
room annex from the control room to the O&M building. A tunnel was constructed connecting
the control roorn to the new operations annex arec. This allowed work release issues to be
addressed in the new annex location, greatly reducing traffic in the control room. Also, the
RFO11 production responsibilities resided with the outage organization which allowed
operations personnel and operations department management to focus more on operational
activities and nuclear safety. This was a significant improvement over RF010 when operations
personnel had significantly more outage production responsibilities.
Prior to the start of RFO11, the plant manager conducted procedural adherence training with all
site personnel emphasizing the need to stop and change procedures, when needed, before
performing the work. Key examples were used to clearly illustrate the potential nuclear safety
and economic consequence of not following plant procedures. Other longer term procedure-
related actions were planned to improve procedure quality and the u::e of the procedure change
process. On February 10, the inspector also attended an outage update meeting held by senior
site managers to communicate directly with the work force on overall 1936 nerformance,
ALARA results, RFO11 scope and management expectations. One expectation discussed was
the need to perform work right-the-first-time and focus on work quality. Other specific events
and noteworthy observations are detailed in the follov.ing sections.
O2
Operational Status of Facilities and Equipment
O2.1 (Onen) VIO 97-01-01: Manual Reactor Scram
a.
Insoection Scope (71715. 93902)
On the evening of February 14,1997, with reactor power at about 28%, operators were
in the process of a plant shutdown for a planned refuel outage when a malfunction
occurred in the feedwater control system causing vessel level to rise above the normal
band. During the subsequent operator responses to this malfunction, reactor water level
approached the MSIV Group 1 isolation setpoint and the operators manually scrammed
the reactor. The inspector was in the control room at the time of the event during deep
backshift inspection and observed the equipment and operator responses during the
event. All related procedures were reviewed, interviews wera held with key crew
personnel at well as training department personnel, and plant computer printouts were
obtained to construct a detailed sequence-of-events attached to this report as
Attachment 1.
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4
Once reactor vessel water level stabilized for about 13 minutes, the NWE informed the
outage production personnel stationed in conference room no. 5 of the status of the
shutdown and the decision to continue the downpower by inserting control rods.
Several minutes later vessel level again began to rise as steam flow decreased with
control rod insertion, again indicating a feedwater control system malfunction. Uncertain
of the cause of the vessellevel increase, the nuclear operations scpervisor (NOS)
initiated appropriate actions ta manually scram the reactor prior to any automatic
actions. The inspector noted that the operating crew did not inform operations
department management or engineering personnel of the FRV problems and proposed
action to continue with the shutdown. Operators entered EOP 2 when four control rod
bottom lights did not illuminate due to a longstanding operator work around condition.
Approximately 14 minutes after the scram, the MSIVs closed on a Group 1 isolation
signal. Difficulty was experienced establishing letdown to lower vessel level due to a
longstanding operator work around on CV-1239.The operating crew did an overall good
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job controlling the plant post scram actions. Shift supervision provided timely and
effective briefs; operators took appropriate action to manually scram the plant; and EOP
usage was excellent.
Pressure control difficulties were experienced and are considered repetitive. The SRV's
were used as an alternate means of pressare control. The HPCI turbine was started in
the pressure control mode but quickly isolated due to the " swell" effect of the vessel
water level. Operators then started RCIC which remained in service. The simulator
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response for shrink and swell did not match the plant response during the event
according to the operators. This led the operators to believe that HPCI could be placed
in service with vessel level at 38" without causing a HPCI trip on high vessel level due to
swell. This also occurred during a prior scram (i.e., April 1996) when HPCI trippad 3
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times on high vessel level. Additional training was given following the April 1996 scram
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on the use of HPCI and RCIC following a scram but apparently there were simulator
modeling discrepancies.
BECo plans to install an upgraded simulator model in mid 1998. The de. lay is due to the
need for several weeks of down time balanced with the simulator availab3ity needs of
the initial license and requalification classes. No code safety valves lifted, and no
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automatic ECCS injection occurred.
During both phases of the event, the inspector observed that occasionally the NWE had
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a tendency to remain stationed at the 905 panel with the reactor operators which tended
to reduce the effectiveness of the typical command-and-control through the NOS. The
NOS became aware of the decision to start /stop feed pumps when he also went to the
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905 panel. Later during the first event, phase, with an increasing vessel water level, the
NWE spoke directly to the 905 operator indicating that a reactor scram would be needed.
Also, four operators stationed directly in front of the 905 panel had the potential to
become a distraction for the 905 reactor operator during a more challenging scenario.
The inspector determined that less than fully effective command-and-control existed
during the event due to weak NWE-NOS communications.
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Operations department management initiated an independent review of operator actions
by operator training personnel. The thrust of this review was to identify any lessons
learned. The inspector considered this independent review was a positive initiative. The
inspector also noted as positiv. 'he quick initiative shown by BECo to form an issue
team to resolve the FRV probic...s and the presence of QA in the control room to monitor
the shutdown.
c.
Conclusions
Operators responded well overall to a difficult FRV malfunction by initiating a manual reactor scram prior to any automatic actions occurring. Operator actions stabilized plant
conditions without any automatic core injection or lifting of the code safety valves.
After the first phase of the event, the operating crew notified outage management
personnel but did not consider notifying operations department management or
engineering personnel before recommencing the shutdown. One violation (VIO 293/
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97-01-01 [first example]) of the abnormal procedure was identified involving the practice
of cycling feed pumps on/off to maintain vessellevelin the normal band to allow an
emergency entry into the condenser bay to manually verify close the "B" FRV. During
operator interviews, an apparent inconsistency between the simulator and plant was
identified involving the effects of shrink / swell in vessel water level. Also, instances of
weak ce nmand-and-control were observed during the event.
02.2 Operational Refuelina Activities
a.
Insoection Scone (71707. 60710)
Operators performed a full reactor core, spiral offload into the spent fuel pool during
RFO11 to facilitate replacement of the core plate plugs. Activities were observed locally
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at the refueling bridge and in the control room. Contract personnel were used to operate
the refueling bridge under the direction of BECo senior reactor operators (SRO).
b.
Observations and Findinas
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At the pre-evolutionary brief (PEB) for offloading the core, the nuclear watch engineer
(NWE) reviewed the precautions and prerequisites for refuel bridge operations in
accordance with Procedure 4.3, Fuel Handling. The communications requirements
between the refuel bridge and the control room were reviewed. Both the plant manager
and vice president of nuclear operations participated in the PEB by providing their
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expectations for a deliberate and controlled core offload. Status boards were set-up in
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the control room to mimic the reactor core and spent fuel pool grid locations. The
inspector noted that the reactor core status board had been modified to include double
blade guides to allow more rigorous tracking. This was a lessons learned applied from
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RFO10 when two control rod events occurred. Extensive preparations for core offload
were evident.
The contract fuel handlers operated the refueling bridge in the manual electric mode
during the periods of reactor core fuel offload observed by the inspector. The SRO
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stationed on the oridge maintained direct and effective control over the contract fuel
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handler activities. Operations support personnel independently verified, using a remote
camera, the proper identification of each fuel bundle prior to transfer into the spent fuel
- pool. Operations department management and quality assurance personnel (QA
Surveillance 97-053) were observed providing oversight and independent assessment of
the fuel movements locally on the bridge. The reactor core fuel offload stopped for
approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the refueling mast airline take-up reel spring broke. A
temporary repair was made to the spring and core offload recommenced. Control room
operators closely monitored the source range monitors (SRM) during fuel movements.
No fuel bundles were observed that were either dropped or banged.
Fuel bundle #YJA708, of the General Electric 11 vintage, was removed from the core
early in the offload and placed in the fuel preparation machine for inspection and repair.
As documented in NRC inspection report no. 50-293/96-06, Section E.2.1, dated
October 30,1996, BECo detected and suppressed local power around a very small fuel
leak. BECo contracted General Electric (GE) during RFO11 to identify the leaking bundle
using TP97-023, Fuel inspection and Bundle Repair. GE contract workers identified that
fuel rod A-3 of bundle #YJA708 had a partial circumferential crack at a location 46
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inches from the bottom of the rod. PR 97.9139 was initiated to document the
inspection results. A replacement fuel rod was manufactured which was intended to be
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inser+ed in the reconstituted fuel bundle #YJA708. Due to the nature and location of the
1
crack in fuel rod A-3, a decision was made to remove all other fuel pins (i.e., except A-3)
of bundle #YJA708 to reconstitute a newly arranged bundle. All fuelintended to be
reloaded into the core was scheduled for in-pool gas sipping to ensure integrity of the
i
i
Near the end of the offload on February 24,1997 with approximately 44 bundles
'
remaining in the core, the inspector observed that the "C" SRM steadily indicated 100
counts /second which was noticeably higher than the "A", "B" and "D" SRMs. The
inspector questioned the operability of the "C" SRM and its impact on fuel movements in
that core quadrant. Operations personnel informed the inspector that although the "C"
SRM indicated higher than the others, that the "C" SRM had steadily decreasing counts
to this point in the offload. Core offload activities continued. The "C" SRM had been
responding to the daily functional test for neutron response. Several hours later with no
fuel left in the vessel, the "C" SRM steadily indicated 100 counts /second. Operations
personnel initiated problem report (PR) 97.9145 to identify possible corrective actions.
The inspector obtained and reviewed a plant computer trend plot for the four SRMs from
February 23 at 14:55 to February 24,1997 at 14:55. The "C" SRM indicated at least
approximately four times higher than the others but trended downwards until flattening
out at 100 counts /second. The system engineer suspected that a calibration problem
may exist with the pulse height discriminator settings. Operators initiated PR 97.9145
j
to obtain corrective actions for the "C" SRM which were planned prior to commencing
fuel reload.
.
The inspector observed operators shift the augmented spent fuel pool cooling from
operating mode 1 into mode 2. This was done at an earlier than planned stage when
l
temperature stratifications between the cavity and spent fuel pool began to increase.
>-
.
7
The pre-evolutionary briefing held in the control room was thorough. The evolution went
smoothly and effective communications from several remote locations resulted partly due
to new portable communications equipment. Effective operations department
management oversight was evident.
c.
Conclusions
The spiral, full core reactor fuel offload was completed in a controlled manner with
effective BECo oversight of contract fuel handlers and no dropping or banging of fuel
bundles. Fuel movement was appropriately stopped to repair the refueling mast air line
take-up reel spring. Fuel bundle gas sipping, inspection and reconstitution activities were
performed using approved procedures. Quality assurance and operations department
management oversight was evident. One equipment problem was identified near the end
of the fuel offload process with the "C" SRM which operations personnel responded to
adequately. Changes in the operating modes of augmented spent fuel pool cooling were
well controlled.
04
Operator Knowledge and Performance
04.1 (Ocen) VIO 97-01-01: Broken Lockino Device For Valve 1301-36
a.
Insoection Scope (71707)
A general walkdown was performed on the reactor core isolation cooling (RCIC) system
to verify that valves and switches were in the normal standby line-up.
b.
Observations and Findinas
,
RCIC system valves, breakers and switches were in the correct position to support RCIC
system operability. However, the inspector identified that the locking device for valve
1301-36, RCIC steam line drain pot trap upstream block valve, was broken with the
valve in the specified open position. The locking device was a blue plastic tie wrap. The
inspector immediately informed two reactor operators working nearby on fire
i
extinguishers. Upon closer inspection of the broken plastic seal, it became evident that
the heat from valve 130136 caused the plastic to neck down and break. A second
valve in the same line subject to the high temperature conditions, 1301-37, RCIC steam
line drain pot trap downstream block valve, also had a blue plastic sealinstalled but had
not melted.
The inspector reviewed the related procedural configuration control procedures. Piping
and instrument drawing (P&lD) M245, RCIC System, Rev E26, depicted valve 1301-36
as normally locked open. Procedure 2.2.22, RCIC System, Rev. 47, Attachment 3,
Valve Checklist, Section 4, lists the normal position of valve 1301-36 as locked open.
Procedure 8.C.13, Locked Component Lineup Surveillance, Rev. 45, Attachment 1, listed
valves 1301-36 and 1301-37 as locked open and specified to use a nonplastic seal due
to high temperature conditions experienced during reactor power operation. Further,
step 6.0[2] of 8.C.13 stated not to use plastic valve restraints where high temperature
a
.
8
may cause the plastic to melt. The inspector determined that the broken plastic lockseal
on valve 1301-36 and the use of plastic lockseals on 1301-36 and 37 was a procedural
violation (VIO 293/97-01-01 [second example]). of 8.C.13 and 2.2.22. This was the
second example of the violation for failure to follow procedures.
The NWE initiated a problem report and had metallic locking devices instal!ed on valves
1301-36 and 37. The operations department manger acknowledged that the use of
plastic lock seats on the aforementioned valves represented an operator human
performance issue. The inspector noted that procedure 8.C.13 referenced quality
assurance (QA) deficiency report (DR) 2065 (Surveillance 95-012), dated January 31,
1995, which was classified as a significance level ll. At that time, BECo QA personnel
identified multiple valves in 8.C.13 that were not adequately secured, one of which was
the same valve (i.e., 1301-36) which had a melted locking seal. One corrective action
taken by the operations department to address the QA concerns in DR 2065 was to
revise 8.C.13 to provide specific guidance on which valves require "non-mettable"
locking devices. The inspector confirmed that 8.C.13 had been revised to provide the
additional guidance. The problems observed by the inspector during this inspection
period resulted solely from operator failure to follow the revised guidance of 8.C.13 to
use metallic locking devices for high temperature applications. Lastly, the inspector
noted that operations personnel did not detect the melted locking devices in January
1995 or again during this inspection period during the operations department self
assessment process.
c.
Conclusions
The use of plastic lock seals for locked valves in high temperature systems resulted in
the NRC identification of a melted locking device on valve 1301-36 and a procedural
adherence violation (293/97-01-01 [second example]). This was a repeat finding since
BECo quality assurance personnel identified a similar concern in January 1995.
Operations department management acknowledged that this violation resulted directly
from adverse operator human performance by not following procedure 8.C.13.
II. MAINTENANCE
M1
Conduct of Maintenance
M1.1 Eg. 3ral Comments
a.
Insoec ion Scope (62707.61726)
The inspector observed / reviewed portions of the following maintenance and surveillance
activities to verify proper calibration of test instruments, use of approved procedures,
performance of work by qualified personnel, and conformance to technical specification
(TS) limiting conditions for operation.
MR P9403796,
Residual heat removal (RHR) breaker preventive maintenance
MR P9403856,
"B" Emergency diesel generator (EDG) refueling outage
preventative maintenance
'
1
9
.
MR 19600453,
inspect valve MO-1400-4B for excessive wear, damage, or
pitting
1
e
MR P9501375
"B" RBCCW heat exchanger disesseinbly, eddy current
l
testing, preventive repairs, and
installation of new channel head.
e
MR 19700434
& 19602452
Troubleshoot and repair the "A" FRV (FV-642A)
-
b.
Observations and Findinas
7
Major "B" loop maintenance work on the EDG and RBCCW beat exchangers progressed
well. The inspector visually examined the RBCCW heat exchanger tube sheet, reviewed
j
the results of the 100% eddy current testing of the tube wall thicknesses and observed
'
mechanics prepare to plug one tube. A system engineer functioned as the maintenance
supervisor as a collateral RFO11 outage duty. Overall condition of the heat exchanger
was very good. Only one new tube required plugging, several tube inserts needed
replacement and some minor balzona repair was needed on the face of the tubesheet.
The inspector observed some small c!am shells located inside the tubes after water
lancing was completed. The mechanic informed the inspector that the clam shells would
be removed prior to reassembly of the heat exchanger. The eddy current vendor made a
recommendation to BECo that methods to reduce clam shells from reaching the tubes
,
should be evaluated to minimize the potential for tube erosion / corrosion.
The "B" RBCCW heat exchanger work package remained up-to-date. The lead mechanic
was very experienced and showed the inspector a newly acquired hydraulic plugging
-
tool. The inspector identified some scratches in the seating surface of the tubesheet on
the c.hannel end at the 6:00 o' clock position. Later, a quality control and engineer
j
inspection of the scratches determined that the scratches needed to be buffed out. The
vendor was contacted to determine the method to be used. The new channel head was
constructed with increased overall thickness. Mechanics professionally rigged the new
channel head into place. Overall, the heat exchanger work progressed smoothly and
nuclear safety was enhanced by the inspections performed, repairs performed and the
increased rigor of the new channel head design.
The inspector reviewed the issue team progress on troubleshooting FRV problems
experienced during the shutdown that led to the scram. BECo hired a contractor
(Framatome Technologies) to conduct state-of-the-art air operated valve diagnostic
testing. The test data revealed that the "A" FRV stroked erratically due to sticking or
binding and more importantly the profile of seat loading vs. displacement led BECo to the
determination that a valve internals problem could exist. Workers disassembled the
valve for inspection and measurements. The valve disc has two separate seating
surfaces which BECo determined were slightly out of tolerance such that one seat was
fully seating while the other was not. The inspector visually examined the valve
internals. The troubleshooting progressed wellidentifying an internals problem which
was addressed by lapping the disc until both seats seated fully. Also, the diaphragms in
the air-operator needed replacement since the glycol fill leaked out. The "B" FRV was
a
.
10
diagnostically tested and found to stroke smoothly and seat properly. Lastly, the
start-up FRV (FV-643) was also tested. BECo intended to re-perform the diagnostic
testing after completion of corrective maintenance to ensure the "A" FRV was in proper
working order.
During the inspection of the work activities on MO-1400-48, "B" loop core spray full
flow test valve, the inspector observed that the maintenance and engineering supervisors
frequently monitored the job progress. Personnel worked within the scope of the job
activity as evidence by the stoppage of work when mechanics discovered anomalies on
the upstream disc seating area of valve MO-1400-4B. A problem report and
maintenance request were generated to resolve this condition.
l&C procured a new computer driven tester to troubleshoot neutron monitoring detectors
i
and cables with more precision. As a result, two IRM detectors did not need to be
replaced this outage. Also, l&C used programmable pressure calibration units for more
accurate and timely calibration of pressure and level devices. The inspector noted the
efforts to obtain newer and better work tools used by the l&C and maintenance staffs.
c.
Conclusions
Major RFO11 work activities progressed well. During the work on the "B" RBCCW heat
exchanger, the troubleshooting on the "A" FRV, and neutron monitors, the use of new
5
and better tools (i.e., tube plug hydraulic *nstallation tool) and technology (air-operated
valve diagnostics) was considered a strength. Workers were noted to be experienced
and stopped when adverse conditions were identified to obtain proper corrective actions.
M6
lAaintenance Organization and Administration
M6.1 Refuelina Floor Maintenance Activities
a.
Inspection Scone (62702,36800)
Portions of the refueling floor maintenance activities were observed including the
containment head and reactor vessel disassembly process. BECo utilized a new refueling
organizational structure during RFO11 as a result of lessons learned from RFO10 and
ideas obtained through peer visits to other nuclear facilities.
b.
Observations and Findinas
The refueling maintenance crews were composed of personnel from BECo and General
Electric contractors. A BECo refueling floor manager provided overall direction and
coordination of refuel floor activities. A new elevated work station constructed on the
refueling floor just prior to RFO11 provided a centralized location for the refueling
I
manager to provide oversight. Two floor coordinators worked on the floor directly with
the work crews in constant communication with the refueling manager.
Removal of the three layers of cavity shield plugs went smoothly with the last layer
remaining m place until moderator temperature was cooled less than 212 degrees
Fahrenheit. The inspector verified that BECo completed a 10 CFR 50.59 safety
7 _ __
. - . _ _ _ . _ _ _ _ __ __
_ _ _ _ _ _ _ _ .
_ ._ . _ _ _ .
-
.
11
evaluation that concluded that an unreviewed safety question (USO) was not created
"
when removing the first two layers of shield plugs during reactor operation. Some minor
difficulty was experienced in setting down the reactor vessel head insulation package.
The load path was partially blocked by the reactor head strongback which was
subsequently moved using a come-along. The refuel floor manager effectively stopped
workers from tilting the insulation package when suspended from the overhead crane.
instead, the overhead crane was moved to obtain the necessary clearance to land the
insulation package. During this time period the inspector observed a worker resting his
head on the come-along that was left tensioned on the head strongback and notified the
refuel manager for corrective action. The inspector considered this a potential personnel
sa'ety hazard.
l
Some problems were experienced when detensioning the reactor vessel head nuts using
procedure 3.M.4-48.2. The reactor head carousal contained four stud tensioners,
!
reactor head nut rack and two high speed nut runners to remove the nuts once loosened
i
by the tensioners. Tensioner no.1 developed a hydraulic fluid leak. In parallel with
i
repairing the leak, a procedure change was obtained to allow detensioning to continue
i
using two tensioners vice four. Later, tensioners nos. 3 and 4 would not break free their
'
associated nuts. The tensioner vendor provided technical support to troubleshoot the
i
tensioner problems. After approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the refuel floor manager decided to
j
replace'the new style tensioners with the old ones which require more manual action.
'
The old tensioners operated nicely and the crew detensioned the head nuts without .
further problems or delay. The new style stud tensioners were first used during HF010
but did not work properly. The inspector observed that the detensioning crew worked
smoothly together with no problems. Favorable radiological conditions existed in the
cavity area compared to past RFOs due to the decontamination measures taken at the
end of RF010. The general area cavity dose rates were approximately 20-25
mrem / hour. Adverse radiological cavity conditions during past RFOs required the use of
shielding blocks that blocked easy access to the vessel nuts during
tensioning /detensioning. After the reactor head was removed, the vessel internals were
removed without any notable problems.
I
c.
Conclusions
l
The refueling floor maintenance crew performed well during reactor vessel disassembly
activities with effective refueling floor management oversight. Equipment problems were
experienced with the new style reactor stud tensioners that resulted in some additional
radiation exposure to work crew in the cavity. The new style stud tensioners did not
work properly during RFO10 either. After installing the old stud tensioners on the head
carousel, the refueling crew demonstrated excellent teamwork while removing the
reactor head stud nuts. Favorable radiological conditions in the cavity, which resulted
from decontamination efforts at the end of RFO10, allowed for easy access when
detensioning and removing the reactor vessel head stud nuts.
-
-
. . -
-
,_
>
12
M8
Miscellaneous Operations issues (92700)
M8.1 (Closed) LER 50-293/97-01: Missed Technical Soecification Surveillance Test for the
Standby Switchvard Battery
a.
Insoection Scope
A review was performed of the corrective actions developed for LER 97-01 and
,
evaluated whether appropriate corrective actions were identified and implemented to
prevent recurrence of the adverse condition.
b.
Observation and Findinas
LER 97-01 documented a historical condition when the plant operated for a period of ten
days without an operable switchyard battery which is in violation of Technical
l
Specification (TS) 3.9.B.5. Specifically, the breaker for the primary switchyard battery
and its associated charger was racked open and the breaker for the standby switchyard
I
'
battery and charger was closed to support surveillance testing. However, the service
discharge test (load profile) of the standby switchyard battery had not been completed
within the required TS interval, every cycle, prior to the battery being placed in service.
i
As a result, the three day TS limiting condition for operation was exceeded.
The corrective actions for this issue included revising the primary switchyard battery
surveillance procedure and the master surveillance tracking program (MSTP) to reflect
the need to test the standby battery prior to placing it in service. In addition, the service
discharge test was performed satisfactorily in January 1995.
The inspector reviewed procedure 8.9.8.4, "125V DC Station 650 Primary Battery
Acceptance, Performance, or Service Test," and verified that it required that the
operability of the standby switchyard battery be verified prior to being placed in service.
A review of the MSTP was also performed to determine if the surveillance tests for the
TS required batteries had been performed and were current. A review of the MSTP
revealed that the performance test (capacity) for the standby battery was scheduled for
October 31,1997. The last performance of this surveillance was December 1990.
Technical Specification 4.9.A.d requires that the performance test be performed every
five years. If the primary switchyard battery were to be taken out of service for
surveillance testing, and the licensee used the MSTP to verify operability of the backup
battery, the licensee could have violated TS, again,
c.
Conclusions
l
The licensee failed to schedule the standby switchyard battery performance test in
accordance with TS requirements. The failure to establish the proper surveillance
interval for the standby switchyard battery is a violation of 10 CFR 50 Appendix B,
Criterion XVI, " Corrective Action." (VIO 293/97-01-02 [first example])
l
.
.
3
b.
Observations and Findinos
The event occurred in two phases, the first phase occurred when operators responded to
the increasing reactor vessel water level by tripping / restarting feed pumps to maintain
level while making an emergency entry into the condenser bay to manually close the "B"
feedwater regulating valve (FRV). After these actions were taken, reactor vessel water
level stabilized for approximately 13 minutes until the decision was made to continue
with the shutdown by inserting control rods to enter RFO11. At this point, the second
phase of the event occurred when the reactor vessel water levelincreased again, and the
operating crew manually scrammed the reactor. The post scram recovery efforts were
complicated when the main steam isolation valves (MSIVs) closed due to a Group 1
isolation signal. The net effect of three operator work around conditions complicated the
recovery efforts, but at no time did the code safety relief valves (SRV) lift or was any
automatically initiated core injection system initiated due to effective operator actions.
The NRC assessment of the three operator work around conditions (i.e., rod bottom
lights, RWCU letdown, MO-220-3) are further discussed in Section E2.1 of this report.
During the first phase of the event prior to the manual scram, the crew believed the
problem was with the "B" feedwater regulating valve (FRV) based on control room
indication of higher than expected flow on the "B" feedwater line with the valve shut.
The crew reviewed related procedures and discussed a course of action. The decision
was made to attempt to manually close the "B" FRV and to stop/ restart reactor
feedwater pumps (RFP) as needed to control vessel level until the "B" FRV could be
verified shut from the field. After two RFP stop/ start evolutions with vessel level
peaking at 43" and bottoming out at 30", the control room received word from the field
that the "B" FRV had been manually closed. Control room indication showed a decrease
in flow on the "B" feedwater line and vessellevel turned at about 43" and began to level
out in the normal band of 30" to 31". During the evolutions of stopping and restarting
feedpumps, the "A" RFP failed to start due to an electrical breaker lockout. Also, large
amperage swings were noted on the "A" condensate pump and large differential
pressure swings were observed in the condensate demineralizer system. Problem reports
were written by operators to address these issues.
Interviews of training department personnel revealed that operators were never trained to
cycle feed pumps on/off with the turbine online. During the interviews, operators did not
consider the FRV malfunction placed the unit in an emergency condition pursuant to
10 CFR 50.54X. The inspector reviewed procedure 2.2.49, Loss of Normal Feed and
Feedwater Control Malfunction. Step 4.2.2, Failure of Both Feedwater Control Valves,
specifies to monitor vessellevel and perform the following as appropriate: if levelis
increasing, then the feedwater pump minimum flow valves may be cycled to aid in
controlling water level. If water level cannot be controlled, then manually scram the
reactor and enter procedure 2.1.6. The crew's actions to cycle feed pumps on/off to
maintain level violated step 4.2.2 of procedure 2.4.49 (VIO 293/ 97-01-01). This was
the first example of the TS 6.8.A violation. PNPS technical specifications 6.8.A,
Procedures, specifies that written procedures specified in Appendix "A" of NRC
Regulatory Guide (RG) 1.33 shall be implemented. Section 5 of RG 1.33 lists abnormal
procedures.
P
.
13
111. ENGINEERING
E2
Engineering Support of Facilities and Equipment
E2.1 Operator Work-Around Conditions
a.
Inspection Scone (37551,92903,93702)
A review was performed of the three operator work-around conditions (i.e., control rod
bottom lights, RWCU letdown, MO-220-3) that came into effect immediately after the
Fcbruary 15,1997 reactor scram discussed in Section 1.02.1 of this report. The
February 15,1997 scram this period had some similarities to a previous scram on
April 19,1996, which was documented in NRC inspection report 50-293/96-03, in that
following both low power scrams, three significant work-around conditions came into
effect after the MSIVs closed due to a Group 1 isolation signal. The work-around
conditions forced operators to enter an additional EOP and generally made recovery
efforts more complicated.
b.
Observations and Findinas
The first operator work-around involves control rod bottom lights that temporarily do not
illuminate after a scram which is a common BWR issue with generic guidance issued
since 1991. This has been a longstanding condition at PNPS. This becomes a
distraction because operators are forced to take compensating actions to verify the rods
were full-in and possibly enter EOP-2, Failure to Scram. After the April 19,1996 scram,
j
46 of the 145 total rods did not have full-in indication. Operators did not enter EOP 2
i
for 16 minutes after the scram which was viewed as somewhat slow. The inspector
identified after the April 19,1996 scram that the operations and engineering personnel
did not even track this as a work-around condition since the compensatory actions were
proceduralized. The inspector considered the practice of accepting and not correcting a
known and degraded equipment condition was poor. At the inspection exit for NRC
i
inspection report no. 96-03, the vice president of nuclear operations committed to
implement a hardware modification to ameliorate the condition. After the February 15,
1997 scram, four control rods did not have full-in position indication again forcing
operators to enter EOP-2.
The second operator work-around involves establishing letdown from the RWCU system
j
to radwaste or the condenser to lower reactor vessel water level. Establishing letdown
was a priority during both aforementioned scrams since the MSIVs were closed and
reactor vessel water level was high. This has been a longstanding condition since at
least 1982. The inspector noted two different challenges associated with establishing
!
letdown. First, operators were procedurally directed to locally override interlocks
l
associated with flow control valve CV-1239 which allows opening the valve during
l
power operations. Specifically, operators install a nut to mechanically gag the related
solenoid valve. During interviews with operators, the inspector became aware that the
solenoid valve was located in the rea : tor building in a locked high radiation enclosure.
!
l
s
.
14
After installing the nut, operators typically experience the second difficulty that involves
establishing letdown flow. Extremely small controller adjustments at control room panel
904 result in relatively large swings in FCV position. The surge typically causes the
RWCU system to isolate on high resin temperoture. Engineering and maintenance
personnel have been ineffective to date ir .aproving the controller response. During
.
both aforementioned scrams, the nuclear nut had to be installed locally and then RWCU
isolated due to the nature of the controller. The operations department manager
considers this to be an engineering design issue. Like the control rod bottom light
work-around condition previously discussed, this condition was also proceduralized
requiring operators to take compensatory actions. Again, the inspector considers this
approach to be poor since post transient response can become more complicated. At
the end of this inspection period, the inspector was informed that corrective actions
were intended to be taken during RFO11.
The third operator work-around condition involved main steam drain valve MO-220-3
located in the condenser bay. After MSIV closure, operators must equalize pressure
between the inboard and outboard MSIVs prior to re-opening the MSIVs. MO-220-3 is a
non-safety related motor operated valve which must be opened during the evolution.
During both aforementioned post reactor scrams, MO-220-3 did not opecate remotely by
switch from the control room. An operator had to be dispatched locally t > the condenser
bay to open the valve.
In the aggregate, these three operator work-around conditions detracted from Pie
operator's ability to promptly stabilize plant conditions during post scram condi ions with
t
a MSIV Group 1 isolation. All three work-arounds experienced during the Aral 19,1996
post scram, recurred again during the February 15,1997 post scram. Since the
corrective actions were not timely, these work-arounds were considered tc be a
condition adverse to quality in violation (293/97-01-02 [second example]) Apper. dix B,
Criterion XVI, which requires prompt and effective corrective actions. The inspector
further notes that the nature of these work-around conditions suggests a tolerance for
degraded equipment conditions and weakness in the effectiveness of the interface
between operations and engineering.
c.
Conclusions
Three longstanding degraded equipment conditions (i.e., control rod bottom lights,
RWCU letdown controller, and MS-V-3) came into effect during the February 15,1997
,
post scrarn recovery. These conditions were adverse to quality and required operators to
take compensatory actions complicating the post scram recovery with the MSIVs closed
due to a Group 1 isolation. These conditions were in violation (293/97-01-02 [second
example]) of 10 CFR Part 50, Appendix B, which requires timely and effective corrective
actions. Further, the existence of the these work-arounds callinto question the
effectiveness of the interface between operations and engineering.
I
i
l
15
E4
Engineering Staff Knowledge and Performance
E4.1 Enaineerina RFO11 Involvement
<
.
A.
Insoection Scooe (37551)
The inspector witnessed the degree of engineering input and involvement in various
RFO11 activities.
b.
Observations and Findinas
During RFO11 many engineering personnel were utilized to staff various outage positions
such as acting maintenance supervisors, refueling teams and production positions. Two
significant issues on the ECCS suction strainers and chemical decontamination of the
recirculation loops emerged shortly before the start of the RFO11. Engineering personnel
prepared the requisite safety evaluations and modification paperwork. PNPS installed
new ECCS suction strainers to increase the amount of design margin available for
suction strainer clogging. The new strainers have a considerably larger surface area than
the old ones. The inspector visually examined the new strainers which came in three
subsections. The nameplate data on the strainers included the following information:
670 square foot surface area, design temperature of 180 degrees Fahrenheit, Material
304-304LSS, maximum differentia! pressure of 12 psid and an approximate weight of
8000 pounds. BECo intended to perform a post work test by running the three ECCS
3
pumps together. The inspector entered the torus several times to observe portions of
l
the work. The BECo project engineer stayed in frequent communication with the BWRs
Owners Group and NRR during the evolution of the issues in NRC Bulletin 96-03,
,
Potential Plugging of ECCS Strainers by Debris in BWRs.
l
Installation of the new strainers into the torus posed several challenges. Since the
prescribed regulatory design specifications were in the process of being developed, BECo
designed the strainers using conservative assumptions with the intent to meet the
j
forthcoming regulatory criteria. The new strainers had to fit thrcugh existing torus
access hatches in the floor o' the reactor building. The three subsections of each
1
'
strainer were assembled in the torus by the use of an automated welding machine which
welded the center pipe internally. Special clamps were designed and fabricated to
temporarily affix the supporting brackets to the torus girders and also a template was
fabricated to ensure proper fit-up when the assembled strainer was lowered into the
water. Divers performed necessary underwater work including drilling holes. Although
torus desludging was in operation, at the earlier stages of the strainer installation work,
the diver visibility in the torus water was very limited. The torus water clarity improved
over time.
Even with the larger surface area of the new ECCS suction strainers, BECo determined
that credit was still needed for a small amount of torus overpressure to mitigate the
potential effects of sludge and fiberglass insulation. BECo previously completed a
10 CFR 50.59 safety evaluation concluding that no unreviewed safety question (USQ)
was involved when the fiberglass insulation was installed onto the recirculation piping in
the mid 1980s. However, BECo was aware of an ongoing NRC review (started in late
.
16
1996) of the licensing basis aspects of the use of overpressure at Pilgrim and submitted
a licensing basis change to NRR for review and approval. Also, BECo submitted a
schedule exemption for the actions contained in NRC Bulletin 96-03. Even thougn the
new and significantly larger strainers were installed during RFO11, the regulatory design
criteria remained under development and thus an exemption was needed. 'Jhe past
reliance on the use of containment overpressure, as evaluated by NRR in Attachment "2"
to this report, was an unreviewed safety question. This area is an unresolved item (UNR
293/97-01-01) pending further licensee and NRC staff review.
One critical path RFO11 work item involved replacement of the swing gate on jet pump
no.11. This work was identified by a BECo engineer while reviewing videotape of the
jet pump swing gate fasteners prior to the outage. The end of the swing gate was not
engaged in the retainer assembly. This condition was confirmed during RFO11 and the
swing gate was replaced. Other jet pumps were verified and any noted discrepancies
'
were corrected or evaluated to be acceptable. The inspector considered the
identification of this issue indicative of excellent problem identification.
c.
Conclusions
The identification of an unlatched jet pump no.11 gate, by a BECo engineer prior to the
outage, while viewing videotape, and subsequent incorporation into the RFO11 for repair
was an example of excellent problem identification and correction. Engineers filled
various outage positions supporting various work teams or production roles. Installation
of the new larger ECCS suction strainers into the torus to increase the margin to
clogging reflected a timely safety initiative by BECo. Credit for a small amount of
containment overpressure will still be needed due to the new and more stringent design
assumptions. BECo submitted a licensing basis change to NRR for review and approval
for the use of overpressure.
IV, PLANT SUPPORT
R1
Radiological Protection and Chemistry (RP&C) Controls
R1.1 As low As is Reasonably Achievable (ALARA)
a.
Inspection Scope (83728)
The inspector reviewed the licensee's collective ra& tion exposure status and dose
reduction efforts currt 7tly planned for the Februairdlarch 1997 refueling outage. This
review included indeg )ndent radiation surveys, review of licensee documents, and
interviews with the R.' staff.
b.
Observations and Findinas
The annual collective radiation exposure at Pilgrim for 1996 was approximately 120.262
person-rem (versus a goal of 142 person-rem), which was the lowest exposure year on
record for Pilgrim Station and corresponds to the top 20% of U.S. BWRs.
,
b
17
During an emergent 2-week outage in September 1996, the licensee discovered that
drywell general area dose rates were 2 to 8 times greater than normal. With a scheduled
refueling outage only 4 months away, the licensee investigated the probable cause, and
developed an action plan to mitigate the effects of an increased source-term. The
licensee's investigation into the cause of increased cobalt-60 plate-out on plant piping
systems determined that increased hydrogen injection, coupled with planned exercising
of control rods to locate a leaking fuel bundle, caused a release of increased cobalt-60
from the core surfaces into the recirculation system. Concurrently, cycling of hydrogen
i
injection caused molecular defects in the corrosion film inside the recirculation system
'
- piping, which. attracted the available cobalt-60 material.
Actions taken by the licensee included a re-evaluation of scheduled drywell work and the
planned deferment of non-essential work activities for a savings of about 120 person-
rem. Additionally, the licensee initiated depleted zinc-oxide injection in December 1996
to retard the possible further increase in cobalt-60 plate-out in plant piping systems. In
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- order to remove the high radioactive source term material, the licensee contracted with a
i
vendor to perform chemical decontamination of the recirculation piping system plus
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portions of RHR system piping inside the drywell prior to the commencement of any
,
affected drywell work. A table of outage dose estimates is provided for companson.
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3
.
18
initial Dose Estimate
Dose Estimate with Dose Reduction
Measures
Outside Drywell 225.5 person-rem
225.5 person-rem
3 chem decon cost
Drywell 471.2
351.2 scope reduction
-234 chem decon effect
17 chem decon cost
Drywell Total 471.2
134.2
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Planned Work 696.7
362.7
(contingency 104.3)
(contingency 76.2)
OUTAGE TOTAL 801 person-rem
439 person-rem
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Other recent ALARA dose reduction actions taken are discussed below.
Fuel pool cooling hydrolase was accomplished resulting in significant reduction of general
area walkway dose rates on the reactor building 91-foot elevation. Additionally, the
i
"A"&"B" RHR pump and heat exchanger rooms have been partially shielded with
)
permanent shielding. Based on direct survey measurements by the inspector, the general
'
area dose rates have been reduced from 50 mR/hr to 40 mR/hr. Half of the piping in
these rooms have not been shielded which has resulted in the marginal dose rate
reduction results. Chemical decontamination of both RHR loops is scheduled for the
third quarter of 1997 and further review for shielding the balance of the RHR piping is
planned.
The I&C group sponsored an initiative to obtain remote measurements of vibration and
temperature of the RHR and core spray pump motor bearings and windings, so that
personnel entry into elevated dose rate areas to obtain these measurements is eliminated
while allowing better monitoring of safety-related equipment.
During RFO11, the maintenance department planned to replace some pump seals with
longer lasting seal designs (recirculation and RWCU pumps). Also, preventive
maintenance has been scheduled on a number of heater drain and dump valves, located
in the turbine building condenser bay, to alleviate the need to do repairs during
operations and under high radiation area conditions. Additionally, the licensee intends to
de-sludge the torus during RFO11 to lower the general area dose rates in the reactor
j
building basement areas. The licensee has been active in eliminating many of the
'
identified " hot spots" and continues to be aggressive in this area.
c.
Conclusions
The licensee has been increasing attention to identify and employ initiatives to reduce
dose rates in the station. The inspectnr noted a significant involvement of the
engineering organization so that the shielding program has shifted from a temporary
shielding program to seeking permanent shielding solutions. In response to an
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19
unexpected and unprecedented jump in drywell dose rates, the licensee's management
demonstrated superior support for the station's ALARA efforts that resulted in
commitments for both depleted zine oxide injection and the chemical decontamination of
recirculation and RHR piping systems. The results of these actions are estimated to
reduce the next refueling outago exposures by one-half.
R2
Status of RP&C facilities and Equipment
,
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a.
Inspection Scope (83728)
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The inspector toured the station and discussed several facility modifications with
!
licensee personnel.
b.
Observations and Findinas
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t
During this inspection, the inspector conducted numerous tours of the plant during
i
operating conditions and noted that ali required radiological postings and locked areas
met regulatory requirements. Ne deficiencies were noted.
)
In January 1997, the principal access point for the RCA, the " red line," had been
completely reconfigured and gready enlarged in order to enhance the flow of personnel
through the principal RCA coundary. An area several times larger has been added with
new personnel contamination monitors and easier access to RP staff behind a large
I
counter area. This new expanded RCA access control point appeared to be' more
I
conducive to personnel flow, however, some further human factor refinements may still
be needed. Although there are the normal administrative controls, at present there are
no built-in barriers to ensure personnel are wearing dosimetry and are properly entered on
an RWP prior to entering the RCA. As the result of chronic contamination control
problems with tools leaving the RCA, the licensee has reconfigured the contaminated
tool depot. Previously, the tool depot (known as Park Street) was small, frequently
pow / stocked and did not provide for contaminated tool return. Currently, the
'
contaminated tool depot has been enlarged to several times its original size, with a
commensurate increase in tool inventory. Also, contaminated tools may be returned to
the same facility, which now incorporates a tool decontamination and monitoring area.
As with the new " red line," the new tool depot has only recently been completed and
the results of these changes remain to be observed during the refueling outage.
!
c.
Conclusions
j
Three facility modifications involving RCA access, have recently been completed, which
directly addressed some chronic contamination control and RCA entry problems by
l
streamlining the process and enlarging capacity. These appear to be excellent
l
improvements to the RP program.
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20
R7
Quality Assurance in RP&C Activities
a.
Inspection Scooe (83728)
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The inspector reviewed the latest RP Program QA audit, se ected QA surveillances, and
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RP self-assessments performed in 1996.
J
b.
Observations and Findinas
i
The October 7,1996, RP program audit included an outside technical specialist and
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focused on appropriate ALARA program areas.' Many observations were made. No-
significant deficiencies were identified. During 1996, many independent QA
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surveillances were performed of various routine RP activities. No significant findings
l
were reported.
i
Several RP self-assessments were reviewed. Those reviewed were of varying quality
j
and focus. One particularly good self-assessment was performed on RP technician dose
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reduction. Others reviewed appeared to have limited value on program performance.
!
c.
Conclusions
!
,
T'1e licensee continues to provide adequate independent oversight of RP activities. The
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effectiveness of the relatively new Rf> self-assessment program remains to be
demonstrated,
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R8
Miscellaneous RP&C issues (92904)
{
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R8.1 (Closed) Violation 50-293/95-09-03: Special Nuclear Material Controls
a.
Inspection Scope
1
On March 29,1995, and on April 6,1995, the licensee reported the loss of a total of
j
seven nuclear detectors containing special nuclear material. All were subsequently
l
found, with two nuclear detectors found offsite. This was a violation of 10 CFR
'
70.51(b)(1), that requires accurate records to be kept indicating the location of all special
nuclear material. The inspector reviewed documents and interviewed licensee personnel
to dete: .ine if corrective actions have been completed to prevent recurrence.
b.
Observations and Findinas
- In a July 21,1995, response letter to the NRC, the licensee determined the cause of the.
violation to be weaknesses in the special nuclear material (SNM) control program
including: procedures, training, and accountability of personnel, immediate corrective
actions included: assignment of a new nuclear material custodian, conduct of a physical
inventory of SNM, and providing locked storage area for portable SNM. Long term
3
.
21
corrective actions included: conduct a physical inventory for portable SNM in the Pilgrim
spent fuel pool, revise Procedure 4.0 on SNM control, revise maintenance procedures
inwiving SNM as necessary, and incorporate a training module on SNM control for
general employee training.
The inspector reviewed the results of the licensee's corrective actions, which included a
review of the following documents:
Procedure 4.0, Rev. 20, "SNM Inventory and Transfer Control"
Procedure 3.M.2-5.6.12, Rev. 6, "TIP Detector Removal and Replacement"
Procedure 3.M.2-5.7, Rev. 6, " Installation and Check Out of the
Fuel Loading Chamber"
Procedure 3.M.2-5.13, Rev.10, "lRM and SRM Detector Change Out"
Procedure 3.M.2-5.14, Rev. 7, "SRM/lRM and TIP Detector Testing"
Procedure 3.M.2-5.1.2, Rev. 7, IRM/SRM Assemblies Removal and Reinstallation
for Dry Tube Replacement"
Radiation Worker Training Program, " Sources of Radiation Lesson Plan",
C-GT-01-02-01, Rev.1
All documents reviewed contained appropriate instructions to ensure prejob briefings
with RP staff prior to any SNM transfer and proper tagging of material, and accurate
completion of accountability and transfer documentation.
A physical inventory of the spent fuel pool was completed on June 30,1996, which
indicated an inconsistency with the documented SNM inventory. Subsequently, on
December 30,1996, a records search was made in order to determine if the documented
SNM inventory was up-to-date and accurate.
The result of the physical spent fuel pool inventory indicated that a total of 14 IRM/SRM
and 4 TIP nuclear detectors were missing, representing a total of 0.056 grams of U-235.
The licensee indicated that these irradiated detectors were highly radioactive and,
therefore, could not have been removed from the spent fuel pool without alarming the
area radiation monitors on the floor and alarming in the control room; and that they were
probably disposed of during one of the spent fuel pool cleanout projects sometime
between 1975 and 1987, when detailed records of less than 1 gram of SNM were not
kept.
The inspector determined, through interviews with licensee personnel, that the
previously lost SNM detectors represented the entire stockpile of damaged IRM/SRM
detectors that had not been irradiated and had been stored in an I & C controlled
laboratory. All other lost nuclear detectors would have been irradiated and would exhibit
very high radiation levels, easily detected by plant radiation monitors. These irradiated
naclear detectors would have been stored in the spent fuel pool. During radwaste
shaments of irradiated reactor hardware, it is likely that the SNM sources were not
recognized or accounted for as components of the nuclear detectors. The devices were
3
.
22
not found during a recent physical inventory of the spent fuel pool. Over a 12-year
period, no SNM transfers were recorded for SNM less than 1 pram and several spent fuel
pool cleanout projects removed accumulated nuclear detectors for disposal over that time
period.
The discovery of the additional misplaced SNM material on December 30,1996, was
initially determined by the licensee to be the result of undocumented transfer of SNM to
e licensed disposal facility more than 10 years earlier. During discussions with the
inspector on January 17,1936, the licensee determined that since no record of SNM
transfer to a disposal facility was made, the misplaced SNM material was technically
lost, and an official NRC notification was subsequently filed on January 20,1997.
'
c.
Conclusion
.' ?ter reviewing all of the corrective actions associated with the violation, the inspector
determined all of the actions to have been completed and adequate to prevent recurrence
of the violation. Therefore, this violation is closed. As a result of the corrective actions
,
taken in response to the previously identified violation, the licensee identified additional
]
examples of inadequate control of SNM. Subsequently, an official report of lost SNM
was made (even though the " loss" occurred prior to 1987). The additional issues
,
stemmed directly from corrective actions taken to address NRC violation 95-09-03 and
as such were not subject to further enforcement actions at this time.
j
R8.2 (Closed) Violation 50-293/96-02-03: Calibration Scerce Lockina Device
'
On March 1,1996, the inspe'ctor entered the licensee's turbine building calibration
laboratory and found a calibration source unsecured due to a faulty locking configuration
and, therefore, unlocked, which was a violation of Technical Specification, Section 6.11.
The inspector reviewed the licensee's corrective actions, which included fabricating a
better locking mechanism on the subject calibration source that would no longer rely on
a chain link engagement to ensure the source was secure in the shielded position. The
inspector was satisfied that the new calibration source lock mechanism would ensure the
source could not be withdrawn from its shield when the lock was secured. This violation
is closed.
-
R8.3 (Closed) Violation 50-293/96-02-04: Radioactive Material Controls
On March 25,1996, detectable contamination was found in a bag labeled radioactive
material at a non-licensed battery recycling facility that originated from Pilgrim Station,
which constituted a violation of 10 CFR 20.1802. The inspector reviewed the licensee's
corrective actions. The licensee determined that the cause of the incident was
j
combining radwaste collection and clean trash collection in transfers to the trash
compaction facility. Ineffective segregation of the wastes resulted in the error. The
licensee revised the trash collection process to preclude co-mingling of radwaste trash
and clean trash. The inspector reviewed procedures 6.1-213 and 6.9-218 and was
satisfied that the trash collection process for clean and radioactive trash is now
completely separate and should prevent recurrence. This violation is closed.
,
,
.
23
R8.4 Updated Final Safety Analysis Report (UFSAR)
a.
Insoection Scoce (83728)
The inspector reviewed current Pilgrim Station practices with Section 12.3.1.1 of the
UFSAR. This section specifies for all areas outside of the controlled area the dose to an
individual will be less than 0.1 rem per year. The inspector examined licensee's data
records for 1996 and interviewed cognizant personnel.
b.
Observations ard Findinas
During 1996, Pilgrim Station was operating at full power for all but 3 weeks of the year
and at an increased hydrogen injection rate between 32 and 38 SCFM. The inspector
reviewed these effects on dose rates at the closest habitation outside the protected area
fence. A review of quarterly TLD data indicates that the I & S building resulted in the
highest location of external exposure to the public equal to 70 mrem / year (based on 40
hours / week). The highest calculated value of internal exposure was determined to be
0.47 mrem / year at a location 150 meters south-southwest of the reactor building based
on continuous exposure. The I & S building location was expected to represent
approximately 38% of the maximum value, and correcting for 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> / week occupancy,
resulted in an estimated 0.041 mrem / year due to internal exposure. Therefore, for 1996,
the maximally exposed member of the public working in the l & S building would have
received an estimated dose of 70.041 mrem TEDE per year.
c.
Conclusions
For 1996, the licensee was in compliance with UFSAR Section 12.3.1.1 and 10 CFR 20.1302. No discrepancies were noted.
S1
Conduct of Security and Safeguards Activities
a.
Inspection Scoce
The inspector reviewed the security program during the period of January 21-24,1997.
Areas inspected included: previously identified items; effectiveness of management
controls; management support; protected area (PA) detection equipment; alarm FtationS
and communication; testing, maintenance and compensatory measures; training and
qualification, and control of vehicles. The purpose of this inspection was to determine
j
whether the licensee's security program, as iraplemented, met the licensee's
commitments and NRC regulatory requirements.
b.
Observations and Findinas
Management support was evident by support for upgrades to the communication
system, including the instellation of new base radio stations in both alarm stations and
installation of new mobile radios in the new security vehicles, the acquisition and
installation of four new security sector post enclosures, and the training of all security
supervisors as first responders for station medical emergencies.
. _ _
_
_
_ _ _ _ _ _ _ _ _ _
_ __
_ _ _ -
_
_ . _ _
_ _ _ _ _ _ _ _ . _ _
_
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P
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Alarm station operators were knowledgeable of their duties and responsibilities and
security training was being performed in accordance with the NRC-approved training and
qualification (T&Q) plan. Management controls for identifying, resolving, and preventing
-
programmatic problems were effective.
!
The PA detection equipment satisfied the NRC-approved physical security plan (the Plan)
!
commitments and security equipment testing was being performed as required by the
l
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Plan. Maintenance of security equipment was being performed in a timely manner as
l
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evidenced by minimal compensatory posting associated with non-functioning security
(
'
equipment. Two previously identified violations associated with the Access
,
Authorization program were closed; however, an inspector follow-up item (i.e., IFl 96-04-
3
01) associated with degraded assessmeat capabilities will remain open.
1
c.
Conclusions
!
The inspector determined that the licensee was conducting its security and safeguards
l
activities in a manner that protected public health and safety.
S2
Status of Security Facilities and Equipment
!
1
i
S2.1 Protected Area Detection Aids
I
a.
Inspection Scope
r
!
l
The inspector conducted a physical inspection of the PA intrusion detection systems
(IDSs) to verify that the systems were functional, effective, and met the licensee's Plan
commitments.
L
i
b.
Observations and Findings
,
On January 22,1997, the inspector determined by observation and selected testing that
the IDSs were functional and effective, and were installed and maintained as described in
the Plan.
l
c.
Conclusion
l
r
l
The PA IDSs met the licensee's Plan commitments.
!
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S2.2 Alarm Stations and Communications
i
a.
Insoection Scope
i
Determine whether the Central Alarm Station (CAS) and Secondary Alarm Station (SAS)
are: 1) equipped with appropriate alarm, surveillance and communication capability,2)
1.
continuously manned by operators, and that 3) the systems are independent and diverse
i
so that no single act can remove the capability of detecting a threat and calling for
l
assistance, or otherwise responding to the threat, as required by NRC regulations.
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a
!
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25
b.
Observations and Findinas
Observations of CAS and SAS operations verified that the alarm stations were equipped
with the appropriate alarm, surveillance and communications capabilities. The inspector
determined that aggressive maintenance of the system has substantially improved
previously identified weakness in the assessment capability for the operators of the
alarm stations using the fixed closed circuit television (CCTV) cameras. However, due to
the age of the Pan, Tilt and Zoom (PTZ) cameras, maintenance has not been totally
effective in keeping the cameras operable, and a. review of maintenance requests
disclosed that the PTZ CCTV's were very high maintenance items. Adequate
,
compensatory measures were being implemented. During the inspection, the licensee
'
made the decision to replace the aging PTZ CCTV cameras with new CCTV cameras. As
noted in Section IV.S1, an inspector follow-up item associated with marginally effective
l
assessment aids will remain open pending the installation of the new PTZ CCTV cameras
!
and will be reviewed during a subsequent inspection.
!
interviews with CAS and SAS operators found them knowledgeable of their duties and
-
responsibilities. The inspector also verified through observations and interviews that the
CAS and SAS operators were not required to engage in activities that would interfere
with their assessment and response functions, and that the licensee had exercised
communications methods with the locallaw enforcement agencies as committed to in
the Plan.
c.
Conclusion
i
The alarm stations and communications met the licensee's Plan commitments and NRC
requirements.
S2.3 Testina. Maintenance and Comoensatorv Measures
a,
bection Scope
Determine whether programs were implemented that will ensure the reliability of
security-related equipment, including proper installation, testing and maintenance to
replace defective or marginally effective equipment. Add:tionally, determine that when
security related equipment failed, the compensatory measures put in place were
comparable to the effectiveness of the security system that existed prior to the failure.
b.
Observations and Findinas
1
Review of testing and maintenance records for security-related equipment confirmed that
I
the records were on file, and that the licensee was testing and maintaining systems and
equipment as committed to in the Plan. A priority status was assigned te each work
request and repairs were normally being completed in a timely manner for all work
necessitating compensatory measures.
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26
c.
Conclusions
Security equipment repairs were timely. The use of compensatory measures was found
to be appropriate and minimal.
S5
Security and Safeguards Staff Training and Qualification
a.
Inspection Scope
I
Determine whether members of the security organization were trained and qualified to
perform each assigned security-related job task or duty in accordance with the T&Q plan.
<
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b.
Observations and Findinos
i
On January 22,1997, the inspector observed firearms training and qualification on the
,
firearms range and determined that the training was conducted in accordance with the
i
T&Q plan and that the range was controlled in a safe manner. On January 24,1997,
i
the inspector met with the security training staff and discussed the on-shift training.
requalification program and its effectiveness. Additionally, the inspector interviewed a
number of supervisors and officers to determine if they possessed the requisite
j
knowledge and ability to carry out their assigned duties.
i
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c.
Conclusions
{
The inspector determined that training had been conducted in accordance with the T&Q
plan. Based on the supervisors' and officers' responses to the inspector's questions, the
,
training provided by the security training staff was considered effective.
S6
Security Organization and Administration
a.
inspection Scope
4
Conduct a review of the level of management support for the licensee's physical security
j
program.
b.
Observations and Findinas
The inspector reviewed various program enhancements made since the last program
inspection, which was conducted in March 1996, and discussed them with security
,
1
management. These enhancements included upgrades to the security communication
!
system that included installation of new base station radios in both alarm stations and
installation of new mobile radios in the two new security vehicles, the acquisition and
installation of four new security sector post enclosures, and training of all security
supervisors as first responders for station medical emergencies.
.
The licensee has also implemented a safety incentive award program for security force
members that resulted in a significant increase in safety awareness and a major
reduction in the number of safety-related accidents.
y
.
27
c.
Conclusions
Management support for the physical security program was determined to be good.
S7
Guality Assurance in Security and Safeguards Activities
S7.1 Effectivenen of Manaaement Controls
a.
inspection Scope
Conduct a review to determine if the licensee has controls for identifying, resolving and
preventing programmatic problems.
b.
Observations and Findinas
The inspector reviewed the licensee's controls for identifying, resolving and preventing
security program problems. These controls included the performance of the required
annual quality assurance (QA) audits, an ongoing self-assessment program and ongoing
security shift supervisor oversight. The licensee was also using industry data, such as
violations of regulatory requirements identified by the NRC at other facilities, as a
criterion for self-assessment.
c.
Conclusions
A review of the licensee controls, including results, indicated that performance errors
were being minimized and that controls were effectively implemented to identify and
resolve potential weaknesses.
S.8
Miscellaneous Security and hafeguards issues
(Closed) VIO 50-293/96-09-01: Failure to perform an audit of the Access Authorization
'h.
program within 12 months of program implementation and every 24 months subsequent
to the initial audit. (Closed) VIO.50-293/96-09-02: Failure to conduct audits of the
accepted vendor contractor vendor access authorization programs every 12 months.
With respect to these two violations, the inspector determined that the corrective actions
described in the licensee's November 20,1996 letter, in response to the NRC's Notice of
Violation were reasonable, complete and appeared to be effective.
F1
Control of Fire Protection Activities
F1.1 Fire Protection Controls in Preparation for the Refuelino Outaae
a.
Inspection Scope (71750)
The inspector walked down portions of the reactor and turbine buildings to assess
BECo's control of combustible material and adequacy of posted compensatory
firewatches. The inspector also reviewed procedures 1.4.3, Combustible Controls for
>
.
28
Pilgrim Station, and 8.B.14, Fire Protection Limiting Conditions for Operation and
Compensatory Measure Fire Watch Requirements.
b.
Observations and Findinas
in preparation for RFO11 which began late in this inspection period, BECo commenced
construction of scaffolding in many plant areas. During a tour of the facility the
inspector verified that staged planking and as-built scaffolding was construc*ed of fire-
treated wood. The inspector noted that some of the wood was not that typically seen in
these applications. This observation was discussed with a fire protection engineer who
confirmed that a new type of fire treatment was used in which the wood was
impregnated with fire-retardant material. This wood has a different appearance from the
old fire treatment which gave the wood a white-washed look. The newly treated wood
has a more natural finish. The inspector verified that many pieces of this wood were
stamped as fire treated and those that were not looked similar to and were located with
the stamped pieces. Other combustible material; i.e. clean rags, lubricating oil, etc.; was
observed to be stored in approved locations and containers.
1
The inspector also toured the areas to identify fire doors that were propped open to
'
facilitate movement of construction materialin the plant. No unauthorized opened doors
were identified. The inspector confirmed that required firewatches were either
continuously posted or performed their hourly rounds in accordance with approved
procedures.
c.
Conclusions
Preparations for RFO11 in terms of fire-treated scaffold construction material and
combustion loading were in accordance with approved procedures. Observed
firewatches were continuously posted or performed hourly rounds, as required.
1
V. MANAGEMENT MEETINGS
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on
March 18,1997. The licensee acknowledged the findings presented. Individual exit
,
'
debriefs were held by the two regional specialist inspectors at the end of their inspection
weeks.
X4
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 additional verification that licensees were
complying with Updated Final Safety Analysis Report (UFSAR) commitments. For an
indeterminate time period, all reactor inspections will provide additional attention to
UFSAR commitments and their incorporation into plant practices and procedures. While
performing inspections discussed in this report, inspectors reviewed the applicable
j
portions of the UFSAR. No inconsistencies were noted.
,
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INSPECTION PROCEDURES USED
f
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IP 37551:
Onsite Engineering
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IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
i
Problems
l
lP 61726:
Surveillance Observation
3
IP 62707:
Maintenance Observation
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IP 71707:
Plant Operations
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IP 71750:
Plant Support Activities
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lP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor >
t
Facilities
IP 92901:
Followup - Operations
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IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support-
IP 93702:
Prompt Onsite Response to Events at Oper8 ting Power Reactors
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ITEMS OPENED, CLOSED, AND UPDATED
Ooened
VIO 97-01-01:
Operations procedural adherence to FRV abnormal and also locked valve
procedures.
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VIO 97-01-02:
Inadequate corrective actions for 3 operator work-around conditions and
the timeliness for a standby switchyard battery surveillance.
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UNR 97-01-03:
The past reliance on containment overpressure for ECCS pump NPSH
I
calculations was an USQ.
.
Closed
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VIO 96-09-03:
SNM control
VIO 96-02-03:
Unlocked calibratiot rsurce
VIO 96-02-04:
Release of radioactive materials
VIO 96-09-01:
Security access audit
VIO 96-09-02:
Vendor access audits
LER 97-01:
Missed surveillance for switchyard batteries
Updated
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IFl 96-04-01:
Assessment Aids
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LIST OF ACRONYMS USED
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As Low As is Reasonably Achievable
Average Power Range Monitors
BECo
Boston Edison Company
CFR
Code of Federal Regulations
Control Rod Drive
.
Emergency and Plant Information Computer
Engineered Safety Feature
gpm
gallons per minute
l&C
Instrumentation and Controls
IFl
Inspection Follow-Up Item
IR
Inspection Report
LER_
Licensee Event Report
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Motor Generator
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Maintenance Request
Non-Cited Violation
NRC
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
NWE
Nuclear Watch Engineer
Pilgrim Nuclear Power Station
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PR
Problem Report
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Radiological Protection
Systematic Assessment of Licensee Performance
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Senior Reactor Operator
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TM
TS
Technical Specification
Updated Final Safety Analysis Report
Work Week Manager
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2
a
ATTACHMENT 1
Inspection Report No. 50-203/97-01
Event Chronoloav (Recort Section O2.1)
This chronology of events is normalized to 2348 on 2/14/97 at which time the following plant
conditions existed.
(00:00:00 = 2348 on 2/14/97, time in br: min:sec)
,
00:00:00
-
Reactor power @ approximately 28%, continuing power decrease via rod
insertion, "A" reactor feed pump (RFP) in service, "B" and "C" RFPs
secured. "B" feed reg valve (FRV) closed, vessel level control in single
element and feedwater heating secured.
00:06:00
-
Both level channels begin to rise from 31"
00:12:00
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High vessellevel alarm, operators suspect "B" FRV not full closed due to
excess flow indication in the "B" feed line, "A" RFP secured, reactor level
reaches 44" then lowers to 30"
00:15:00
-
"C" RFP placed in servics
00:16:00
Operators dispatched to condenser bay to manually close "B" FRV
-
00:20:00
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"C" RFP secured, vessel level 43"
00:22:00
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Attempt to start "A" RFP fails due to breaker lockout, "C" RFP restarted
vessel level 30"
00:24:00
Field operators report "B" FRV gagged closed, vessel level peaks and turns
at 43"and begins to return to normal
00:42:00
-
Level stable for previous 10 minutes, decision made by watch engineer
(NWE) to continue shutdown
00:47:00
-
Vessellevel begins to rise above 31", reactor power 21 %, scram actions
briefed by operations supervisor (NOS)
Manual Scram @ 40" vessel level, turbine trip per design, vessel level
00:50:36
-
bottoms out at 10" and recovers to normal band, RWCU isolates (per
design)
00:50:46
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APRM's allindicate downscale
00:51:36
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4 control rods do not indicate full in, feedwater block valves closed
00:52:00
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"C" RFP secured, vessel level 43"
00:55:00
-
00:58:00
RWCU in service
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01:04:00
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Group 1 isolation (MSIV's close), RWCU isolated
01:08:00
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All rods determined full in except 14-35 which is at position 02
01:09:00
-
01:12:00
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"A" RHR in torus cooling
01:13:00
-
"B" SRV opened for reactor pressure control
01:14:00
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"B" SRV closed
01:20:00
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RWCU in service
01:21:00
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RWCU trips and isolates on high non-regen outlet temp
01:22:00
RWCU in service
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01:23:00
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"C" SRV opened for reactor pressure control
01:24:00
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"C" SRV closed
01:25:00
-
HPCI started for pressure control, vessel level 38"
01:26:00
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HPCI trips on high vessel level due to swell
01:28:00
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RCIC in service for pressure control
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01:41:00
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Opened outboard MSIV's
01:48:00
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Attempting to equalize pressure around inboard MSIV's, main steam line
drain valve MO-220-3 did not open remotely from the control room,
operator dispatched to open the valve manually in condenser bay
02:01:00
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"B" RFP in service with startup FRV
O2:09:00
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Main steam line drain valve MO-220-3 opened manually
02:55:00
Inboard MSlV's opened, continuing cooldown
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ATTACHMENT 2
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Inspection Report No. 50-293/97-01
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NRR to Region i Memorandum
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dated February 12,1997
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
2
WASHINGTON, D.C. SoseHoot
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February 12, 1997
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MEMORANDUM TO:
Richard W. Cooper, II, Director
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Division of Reactor Projects
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FROM:
Patrick D. Milano, Acting Director
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Project Directorate I-3
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Division of Reactor Projects - I/II
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SUBJECT:
REQUEST FOR TECHNICAL ASSISTANCE REGARDING THE PILGRIM
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LICENSING BASIS AND SUBSEQUENT MODIFICATION UNDER 50.59 FOR
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TWO SAFETY SIGNIFICANT PROBLEMS
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By letter dated July 18, 1996, you requested NRR assistance in evaluating the
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acceptability of the Boston Edison Company (BEco) conclusion that no
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Unreviewed Safety Questions (USQ) exist for two safety significant problems at
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the Pilgrim Nuclear Power Station. This is to inform you that we have
completed our review of Question I regarding the credit for post-accident
containment overpressure to offset the pressure drop caused by debris laden
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emergency core cooling system suction strainers and concluded that it is a
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USQ. Our evaluation is attached.
In addition, based on additional
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information pravided "uy tin 'iicensee, we recognize the fact that the plant
design basi 3 .nclu(es cred*t for oveg ressure. However, since the licensee
never requastea staff review of this feature, it was not incorporated into the
licensing basis. With regard to Question 2 of the TIA, BEco has requested
{
formal review and approval for the credit of containment overpressure. Thus,
-
Question 2 will be answered as part of that review. As we have concluded that
this is a USQ, this is a startup issue and NRR Projects has asked for a
,
mid-March completion time. . If you have any questions, please contact Alan
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Wang at (301) 415-1445.
4
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Attachment: As stated
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cc w/att:
H. Miller, RI
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L. Reyes, RI-
A. B. Beach, RIII
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L. Callan, RIV
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REGION I TIA REGARDING THE PILGRIN LICENSING BASIS Als 9?Mh
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HQDJFICATION UlBER 10 CFR 50.59 FOR TWO SAFETY SIGNIFICANT FW4 LEN
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1.0
INTRODUCTION
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1
By letter dated July 18, 1996 (Reference-1), Region I requested assistance to
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determine the acceptability of the Boston Edison Company (BEco) conclusion
that no Unreviewed Safety Questions (USQ) exist for two safety.significant
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problems at the Pilgrim Nuclear Power Station (PNPS). The questions posed to
the staff are as follows:
.
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1.
"Can BEco credit post-accident containment pressure to offset the
pressure drop caused by debris laden emergency core cooling system
,
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(ECCS) suction strainers without NRC staff review and approval in
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accordance with the 10 CFR 50.59 process; and, overall, is the BEco
safety evaluttion for debris clogging of ECCS suction strainers
3
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adequate?"
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2.
"Can BEco rely on the 'SHEX' computer code for modeling Pilgrim post-
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accident containment temperature and pressure as a result of operating
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the service water system with inlet temperature up to 75 degrees F
!
without NRC staff review and approval in accordance with the 10 CFR
50.59 process; and, overall, is the BEco safety evaluation for inlet
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temperatures from 65 to 75 degrees F adequate with respect (to) the
4
licensing and design basis for the plant?"
1
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The Reactor Systems Branch'(SRXB) has addressed question one regarding whether
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BEco can credit post-accident containment pressure without staff review and
approval, and whether the safety evaluation for debris clogging of ECCS
suction strainers is, adequate. Our review is as follows.
2.0
BACKGROUlO
In 1984, BEco changed the drywell piping insulation from reflective metal
insulation (RMI) to blankets filled with fiberglass. On May 11, 1984, the
i
licensee met with the staff to discuss the utilization of staff guidance
'
provided in draft Regulatory Guide 1.82, Rev.1. Summary of the meeting
issued June 26, 1984 (Reference 2),. states:
The discussion indicated that BECo, with assistance from the General
Electric Company, is utilizing the staff guidance provided in draft
Regulatory Guide 1.82. As a result of its calculations, the ifcensee
intends to increase the area of the suction screens in the drywell to
elininate any degradation of energency core cooling systen pump
.
perfonnance that night otherwise result from blockage of the screens by
insulation debris following a loss-of-coolant accident.
On December 3, 1985, Generic Letter (GL) 85-22 (Reference 3), Potential For
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Loss of Post-LOCA Recirculation Capability Due to Insulation Debris Blockage,
GL 85-22 informed licensees about a generic safety concern
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was issued.
regarding LOCA-generated debris that could block PWR containment emergency
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ATTACHMENT
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sump screens or 8MR RHR suction strainers, resulting in a loss of
recirculation or containment spray pump net positive suction head (NPSH)
margin.
In particular, GL 85-22 states:
Although the staff has concluded that no new'requirenents need be
imposed on ifcensees and construction permit holders as a result of our
concluding analyses dealing with the resolution of USI A-43, we do
reconnend that RG 1.82, Revision 1 be used as guidance for the conduct
of 10 CFR 50.59 reviews dealing with the changeout and/or nodification
of thernal insulation installed on primary coolant systen piping and
components. RG 1.82, Revision 1 provides guidance for estinating
potential debris blockage effects. If, as a result of NRC staff review
of Ilcensee actions associated with the changeout or nodification o'f
thernal insulation, the staff decides that Standarvi Review Plan Section
6.2.2, Revision 4 and/or RG 1.82, Revision 1 should be (or should have
been) applied to the rework by the licensee, and the staff seeks to
impose these criteria, then the NRC will treat such an action as a
' plant-specific backfit pursuant to 10 CFR 50.109.
those plants with small debris screen areas (less than 100 ft ), highItisexpeE
ECCS recirculation pumping requirements (greater than 8000 gpe), and
small NPSH nargins (less than 1 to 2 ft of water) would benefit the nost
from this type of assessment in the event of a future insulation change.
RG 1.82, Revision 0 with its 50% blockage criteria does not adequately
address this issue and is' inconsistent with the technica? findings
developed for the resolutfon of USI A-43.
Although GL 85-22 recommended the use of RG 1.82, Rev.1 (Reference 4), for
10 CFR 50.59 analysis of changeouts of insulation, BECo had already decided to
follow the guidance in 1984. The use of RG 1.82, Rev. 1, was not a NRC
requirement nor was it a plant-specific backfit. The 50.59 analysis of the
new insulation was completed in 1984 using draft RG 1.82, Rev. 1.
The staff
notes that there are only minor editorial changes between draft RG 1.82,
Rev.1, and RG 1.82, Rev.1, issued November 1985.
In early 1996, design information reviews identified that the bases of the
1984 50.59 evaluation used the preliminary head loss estimates associated with
insulation debris rather than the final head loss estimates that were greater
in magnitude.
At the time of discovery, a new 50.59 evaluation, SE 2971, was
prepared which superseded the previous evaluation (Reference 5).
3.0
EVALUATION
3.1
Containment Overoressure
The Pilgrim Safety Evaluation Report (SER) by the AEC (Reference 6), dated
August 25, 1971, discsssed net positive suction head to RHR and Core Spray
pumps in Section 5.7.
5.7 Net Positive Suction Head (NPSH) to RHR and Core Soray Pumos
During the course of the construction permit review on Pilgrin, we
questioned whether the RHR and core spray pumps, and their respective
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systems, were designed to prvvide an adequate NPSH margin to assure
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their continued operation following a loss-of-coolant accident. In
Amendment 9 to the applicatfon, Boston Edison Company furnished an
analysis based on preliminary design assumptions showing that a positive
N?SH margin would be available following the accident without requiring
containment overpressure.
The appitcant provided further information in
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Amendment No. 24 with an analysis confirning the final design
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requirement that a positive NPSH margin be available even if the
containment spray were operating following a design basis loss-of-
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coolant accident (LOCA). We conclude that the equipment provided is
adequate to assure sufficient NPSH to the energency systen pumps in the
(
unlikely event of a LOCA.
'
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In order to understand what may have been the thought processes of the AEC
staff at the time the AEC SER was written, the staff reviewed Amendments 9 and
,'
24, Safety Guide 1, and other supporting documentation. ~In Amendment 9 to the
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Preliminary Safety Analysis Report (PSAR) (Reference 7), the licensee
responded to the following AEC question:
,
Describe and justify the NPSH requirements for the RHRS and Reactor Core
.
Spray Cooling Systen Pumps.
As stated in the AEC SER, Amendment 9 provided a preliminary design analysis
of the total NPSH available for Pilgrim.
The conservative model used to
calculate NPSH available assumed atmospheric pressure, 0 psig, and 100%
humidity in both the drywell and wetwell, with respective temperatures of
150*F and 80'F. At that time, 28 feet was the NPSH required for the RHR and
the core spray pumps.
Figure 1-2 of the submittal showed the containment
pressure req W ed for 28 feet of NPSH during a design basis LOCA.
From Figure
1-2 it can be seen that the peak containment pressure required was
approximately 13.8 psia. This value is below I atmosphere, and hence, the
difference between I atmosphere and the peak containment pressure required for
28 feet of NPSH is positive margin. Thus, the staff concluded that no
containment overpressure was required and positive margin existed.
In addition, the following AEC question was addressed in Amendment 24
(Reference 8):
Provide data on containment pressure (with spray) vs time following a
,
LOCA showing required pressure to assure adequate NPSH to core cooling
i
pumps. Consider data and write up given in Quad Cities Amendments 16
and 17. These data relate to various levels of systen degradation.
!
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The licensee's' response to the question was as follows:
)
'A complete analysis of total NPSH available has been previously
docunnnted in Pilgrin Amendment 9, Comment 1.
This analysis remains
a
conservative with respect to the model and assumptions utilized. The
attached Figure which more closely corresponds to final station design
b
conffras the fact that substantfal NPSH margin will be available at all
4'
times following a design basis loss-of-coolant accident, both with and
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without containment spray.
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The licensee did not address the Quad Cities amendments but provided a figure
which shows that peak containment pressure required is below one atmosphere
during the design basis LOCA with containment spray. The staff notes that no
other data was provided in Amendment 24 besides the figure. The staff
!
reviewed the Quad Cities amendments (References 9 and 10) which showed that
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Quad Cities needed approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of containment overpressure to assure
l
adequate NPSH to the RHR pumps in LPCI mode following a design basis LOCA.
Several differences were noticed between Pilgrim and Quad Cities.
In
Pilgrim's NPSH calculations, the initial suppression pool temperature was
assumed to 80*F whereas Quad Cities it was assumed to be 90*F; Pilgrim's core
spray pumps have a higher NPSH requirement, 28 ft., than the RHR pue s, 23
i
ft., however at Quad Cities, the RHR pumps in LPCI modes had the higher NPSH
{
requirements of the two pumps. Also, the Quad Cities RHR service water pumps
are required to . operate during cooldown of the reactor vessel during
'
operation. This required the Quad Cities pumps to be designed with higher
head capability.
Based on this information, it appears that the AEC was
looking for information regarding the changes in RHR flow requirements with
and without containment spray and its affect on RHR NPSH requirements. Since
Amendment 24 did not show that containment overpressure was needed for
adequate NPSH of both pumps with containment spray, it was concluded by the
staff that positive margin was available. As stated above, this positive
margin is the difference between one atmosphere and the peak containment
pressure required for adequate NPSH during LOCA conditions.
On January 8, 1997, representatives from BEco met with the NRC staff to
discuss how BECo reached the conclusion that installation of the new
i
insulation did not result in an USQ. During the meeting, the licensee stated
that they did not believe that Pilgrim could have been licensed with such a
small NPSH margin, i.e., 0.9 psia, and presented recently acquired documents
from General Electric which discussed the design basis of Pilgrim. The staff
contends that Pilgriin was licensed with the small margin of NPSH which does
not include containment overpressure. This belief is strengthened by
statements such as "small NPSH margins (less than I to 2 ft of water)" in GL
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85-22.
Furthermore, the staff notes that the information presented at the
meeting from General Electric was not docketed or presented to the staff for
review in the past and therefore, is not part of the Pilgrim licensing basis.
Consequently, tne staff finds that Pilgrim's current and past licensing basis
is that no containment overpressure is required for adequate NPSH of the ECCS
pumps with clean strainers.
Based on the above, the staff does not concur
with the licensee that Pilgrim's licensing basis included credit for positive
containment pressure.
3.2
Safety Evaluation 2971
BECo developed Safety Evaluation 2971 (Reference 11) to evaluate the effects
of fiberglass insulation debris on Pilgrim emergency core cooling system
(ECCS) performance (a.k.a. Core Standby Cooling Systems (CSCS)).
SE 2971
references Calculation M-662, "RHR and Core Spray Pump NPSH and Suction
Pressure Drop," and GE Report GE-NE-B13-01805-11, " Effects of Fiberglass
Insulation Debris on Pilgrim ECCS Pump Performance," (References 12 and 13).
Calculation M-662 provides an analysis of NPSH conditions for RHR and Core
Spray Pumps during performance test conditions and following the design basis
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loss of coolant accident, The staff notes that data generated in this
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calculation is currently used for the applicable figures, i.e., 14-5.9, 10,
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and 13, in Chapter 14 of the FSAR (Reference 14), and are based on clean
strainer conditions.
!
During the meeting with the staff on January 8,1997, the licensee stated that
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draft RG 1.82, Rev.1, was followed for their 1984 50.59 evaluation. This
document lists twelve design criteria applicable to the suppression pool and
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the vents and downcomers between the drywell and the wetwell.
These criteria
i
are generally design criteria for screens, trash racks, and ECCS pump intakes.
However criteria 7 discusses debris effects on NPSH available (peference 4).
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7.
Evaluatton or conffraation of (a) suppressfon pool hydraulic
'
performance (e.g., geometric effects and air ingestion), (b) debris
'
effects (e.g., debris transport, interceptor blockage and head loss, and
1
clogging of pump seals by particulates), and (c) the combined impact on
'
NPSH available at the pump inlet should be performed to ensure that
)
long-tern recirculation cooling can be accomplished. An assessment of
the susceptibility of the recirculation pump seal and bearing assembly
- .
design to failure due to particulate ingestion and abrasive effects
i
should be made to protect against degradation of long-tern recirculation
!
pumping capacity.
'
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The staff notes that this criteria was the basis for the 1996 GE analysis
i
(Reference 13) of the impact of using NUKON insulation on the drywell piping
[j
at Pilgrim. The staff did not review the 1984 GE analysis (Reference 15), so
nu conclusion regarding the differences between the two reports can be made.
However, the 1996 GE analysis did not appear to address the. suppression pool
hydraulic performance, particulate clogging of pump seals, or the combined
impact.on NPSH available at the pump inlet. Only the insulation debris
effects of blockage and head loss were addressed in the GE analysis. The
staff believes that criteria 7 in its entirety should have been evaluated in
order to predict NPSH available to the ECCS pumps.
The 1996 GE analysis estimated that 16.2 cubic feet of insulation debris would
be distributed over four RHR and two core spray intake screens in proportion
to the applicable flow rates. On a per strainer basis, this was calculated to.
.
be 2.9 cubic feet for RHR and 2.2 cubic feet for core spray with corresponding
head losses of 13.8 feet for RHR and 5.5 feet for core spray.
These head
losses were then used as inputs in SE 2971 to calculate the NPSH available
with strainers laden with insulation debris.
The current model, as described in SE 2971, used to calculate NPSH available
assumes initial conditions of 1.3 psig,150*F, and 80% humidity in the drywell
and 0 psig, 80*F, and 100% humidity in the wetwell. The licensee stated that
the original initial drywell conditions were not credible conditions to exist
prior to a postulated accident.
The licensee continued to state that although
the original analysis appears more conservative in this regard, there was no
basis for the inconsistent assumptions on the drywell conditions.
It is
unclear to the staff as to how the drywell assumptions are inconsistent since
the containment analysis was not part of SE 2971. The staff believes that the
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containment analysis should be reviewed to verify the adequacy of the new
initial conditions.
The licensee used the new NPSH available model to verify NPSH available with
strainers laden with insulation debris. Table 5 in Calculation M-622
(Reference 12) shows that NPSH available is greater than NPSH required with
clean strainers with inlet service water temperature of 65'F.
However,
Table 5 further shows that NPSH available is not greater than NPSH required
for debris laden strainers (i.e., a deficit of 4.47 ft is shown). This
corresponds to approximately 2 psig of overpressure which is required to exist
in order to meet NPSH required requirements. The licensee stated that the
increase in suction head loss from the postulated debris accumulation is with
in the margin for NPSH available to the ECCS pumps.
In order to clarify their licensing basis with regard to positive containment
pressure, the licensee discussed the curve submitted in Amendment 24 which
showed the effect of continuous containment spray on available containment
- pressure and NPSH available for a DBA LOCA.
In SE 2971, the licensee states
that:
As shown for the spray case, the containment pressure is at or above
atmospheric pressure while the pressure required to meet NPSH
requirements is always less than atmospheric pressure, hence NPSH
available exceeds NPSH required during continuous spray for the noninsi
design case. The original FSAR Figure 14.5-13 does not reflect the
drywell spray reduction implemented via PDC 86-52A or the potential
effects of fibrous debris on available NPSH.
The staff noiies that the new FSAR Figure 14.5-13 does not resemble the
original FSAR Figure 14.5-13 which was submitted in Amendment 24. The current
Figure 14.5-13 also takes credit for positive containment pressure as stated
above, but still does not reflect the effects of fibrous debris on available
NPSH. The staff does not agree with the licensee as presented in Section 3.1.
In the AEC SER, the staff stated that containment overpressure was not
required to have positive NPSH margin during DBA LOCA conditions. This is a
statement of fact not a requirement. Although Safety Guide I was issued by
the time the AEC SER was issued, Safety Guide 1 is not part of the Pilgrim
licensing basis. With service water inlet temperature of 65'F and clean ECCS
strainers, no containment overpressure required for positive NPSH margin
(margin below one atmosphere) remains a statement of fact. However, due to
the new insulation debris, changes to the assumptions of the initial
conditions, and higher service water inlet temperature, discussed in another
SE, the staff believes that probability of a malfunction of equipment
important to safety previously evaluated in the safety analysis report may be
increased.
Since debris from insulation blown off of pipes during a DBA LOCA
increases the probability of malfunction in the ECCS pumps, resulting from
cavitation, the staff believes a USQ exists as described in 10 CFR 50.59(a)(2)(1). As such, changes to the insulation which can cause debris on
the ECCS suction strainers, which have limited margin for NPSH available,
should have been submitted to th staff for review and approval. The staff
believes that the change of insulation and the usage of RG 1.82, Rev.1,
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should have prompted the licensee to propose a licensing basis change from no
containment overpressure required with clean ECCS strainers to some limited
amount of containment overpressure required for debris laden ECCS strainers.
4.0
CONCLUSION
Based on the above information, the staff believes a USQ exists regarding the
installation of insulation on pipes which can cause debris. Also, the staff
does not concur with the licensee that Pilgrim's licensing basis included
credit for positive containment pressure. As stated earlier, Safety Guide 1
is not part of Pilgrim's lic~ensing basis; however, neither is containment
overpressure.
5.0
REFERENCES
1.
Cooper, Richard W., USNRC, to Steven A. Varga, USNRC, " Proposed Task
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Interface Agreement (TIA) Regarding the Pilgrim Licensing Basis and
Subsequent Modification Under 10 CFR 50.59 for Two Safety Significant
Problems," July 18, 1996.
,
2.
Leech, Paul H., USNRC, to Boston Edison Company, " Meeting With Boston
Edison, May 11, 1984," June 26, 1984.
l
3.
Generic Letter 85-22, " Potential for loss of Post-LOCA Recirculation
Capability Due to Insulation Debris Blockage (Generic Letter 85-22),"
December 3, 1985.
4.
Regulatory Guide 1.82, Revision 1, " Water Sources For Long-Term
Recirculation Cooling Following A Loss-Of-Coolant Accident," November
j
1985.
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.
5.
Boulette, E. T., Boston Edison Company, to NRC, " Updated Response to
NRCB 93-02," June 28, 1996.
6.
" Safety Evaluation by the Division of Reactor Licensing U.S. Atomic
Energy Commission in the Matter of Boston Edison Company Pilgrim Nuclear
Power Station," August 25, 1971.
'
7.
Boston Edison Company, Pilgrim Nuclear Power Station, Amendment 9,
March 11, 1968.
8.
Boston Edison Company, Pilgrim Nuclear Power Station, Amendment 24,
March 18, 1971.
<
9.
Lee, Byron Jr., Commonwealth Edison Company, to Dr. P. A. Morris, USAEC,
" Amendment 15 to the Applications for Construction Permits and Operation
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Licenses for Quad Cities Units 1 and 2," February 8, 1971.
10.
Lee, Byron Jr., Commonwealth Edison Company, to Dr. P. A. Morris, USAEC,
" Amendment 17 to the Applications for Construction Permits and Operation
Licenses for Quad Cities Units 1 and 2," March 1, 1971.
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,
11.
Safety Evaluation 2971, Pilgrim Nuclear Power Station, March 25, 1996.
12.
Calculation M-662, Rev. El, "RHR and Core Spray Pump NPSH and Suction
Pressure Drop," March 20, 1996.
13.
GE Document, GE-NE-813-01805-11. " Effects of Fiberglass Insulation
Debris on Pilgrim ECCS Pump Performance," January 1996.
14.
Pilgrim Nuclear Power Station Final Safety Analysis Report, Revision 19,
i
June 1996.
15.
GE Document, AE-076-0884, August 28, 1984.
Principal Contributor:
K. Kavanagh
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Date:
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