ML20209G233
| ML20209G233 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 07/09/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20209G231 | List: |
| References | |
| 50-293-99-03, 50-293-99-3, NUDOCS 9907190095 | |
| Download: ML20209G233 (38) | |
See also: IR 05000293/1999003
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
License No.: DPR-35
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Report No.: 99-03
Docket No.: 50-293 ,
Licensee: BEC Energy
800 Boylston Street
Boston, Massachusetts 02109
Facility: Pilgrim Nuclear Power Station
Inspection Period: April 19,1999, through June 9,1999
Inspectors: R. Laura, Senior Resident inspector
R. Arrighi, Resident inspector
K. Kolaczyk, Reactor Engineer
P. Frechette, Physical Security Inspector
L. Prividy, Senior Reactor Engineer
R. Ragland, Jr., Radiation Specialist
R. Summers, Project Engineer
Approved by: C. Anderson, Chief
Projects Branch 5
Division of Reactor Projects
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, PDR ADOCK 05000293
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EXECUTIVE SUMMARY !
Pilgrim Nuclear Power Station l
NRC Inspection Report 50-293/99-03
This integrated inspection included aspects of licensee operations, engineering, maintenance, I
and plant support. ' The report covers resident inspection for the period of April 19,1999,
through June 9,1999. In addition, it includes the results of Region 1 specialist inspectors; in the
Engineering /ISI area during May 24-28,1999; in the Security area during May 10-12,1999; ;
an operability evaluations initiative inspection during May 10-14,1999; a radiological controls
outage inspection during the week of May 17,1999; and a Y2K readiness review on April 19-23
and May 28,1999.
Operations
- Shift turnover briefings lead by the off going nuclear watch engineer were detailed and
included a good discussion on equipment availability and shutdown risk. (Section O2.1)
. Reactor fuel movements were performed in a controlled manner with effective
communications between contract fuel handlers, reactor engineers, control room
operators and the SRO stationed on the refueling bridge. (Section O2.1)
. Operators stopped fuel movements when necessary to resolve degraded conditions
such as poor reactor water quality and also when a source range monitor started to read
erratically. This reflected a conservative nuclear safety approach by operations I
personnel. (Section O2.1)
. A new camera angle during core verification revealed a fuel support piece which was not
fully seated. Also, a cap screw was removed from a control rod drive which had jamn.ad
the rod during the previous operating cycle. Good FME practices were observed during
refueling activities. Refueling activities were conducted in a controlled manner with
overall good performance. (Section O2.1)
- Several tagging errors resulted due to license operator errors both while hanging and
verifying checking tags. These errors occurred early in RFO12 during the highest
demand period for work release indicating that management involvement was lacking in
the oversight and scheduling of tagouts. Interim corrective actions were implemented to
improve future tagging performance. This severity level IV violation is being treated as a
non-cited violation, consistent with Appendix C of the NRC Enforcement Policy. This
violation is in the licensee's corrective action program as prs 99.9190, 99.1121,99.9264
and 99.9914. (NCV 50-293/99-03-01) (Section O4.1)
. Training provided to licensed operators on modifications implemented during the cycle
12 refueling outage was determined to be good. Simulator and job performance
measures were used, as necessary, to ensure operators could properly operate the
equipment and that they understood the modifications. (Section 05.1)
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Executive Summary (cont'd)
Maintenance -
=
The disassembly and reassembly of the reactor vessel was performed well by the
. - .o - refueling crew. . Good teamwork was noted between the craft and contract personnel.
, (Section M1.1)
=
Several new initiatives were used during the outage including use of electronic logs
which were accessible site wide, new reduced weight heavy-lifting slings, and a
relocated outage work control center. (Section M1.1)
= Pre-job briefs for surveillance activities were determined to be good with proper oversight
provided by the test engineer and quality assurance personnel. (Section M1.1)
=- Post work testing for observed maintenance activities was determined to be good and in
accordance with code requirements. (Section M1.1)
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=- Several procedure usage problems were identified by the licensee and the inspector.
One problem dealt with the mispositioning of LPCI throttle valve MO-1001-28B during
performance of the EDG load sequence test. This severity level IV violation is being
treated as a non-cited violation, consistent with Appendix C of the NRC Enforcement
Policy. This violation is in the licensee's corrective action program as PR 99.1647. (NCV
50-293/99-03-02) (Section M1.1)
= The emergent replacement of the underground SSW discharge piping, replacement of
the DC power panels and CRDM drive change-outs were well planned and executed.
(Section M1.1 and M1.2)
= Deferred work items were properly tracked and dispositioned by the outage review
board. No work items were removed from the outage scope that would adversely affect
safe plant operations.- (Section M2.1)
= BEC Energy was implementing inservice inspection activities in accordance with their ISI ,
program. NDE personnel were qualified, and adhered to procedures while performing ]
examinations. Deficiencies identified during inspection activities were properly
documented. HPCI system weld drawings accurately reflected the location of welds in
the plant. (Section M3.1) )
- The' failure to establish specific procedural guidance and human performance errors i
contributed to the cause of the transformer fire. (Section M3.2)
Engineerina
. No safety concerns were noted conceming the open operability evaluations reviewed. !
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Executive Summary (cont'd) .
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Two minor problems were noted during the review of operability evaluation (OE)98-052,
" Excessive Head Loss in Reactor Building Closed Cooling Water Pump Startup
Strainers." These included attention-to-detail problems pertaining to the procedures
- - goveming operability and engineering evaluations... Also, the preliminary engineering
work supporting PDC 99-09, " Decrease of the EDG Building Low Temperature Design {
L!mit," was not comprehensive. Structural considerations were not being reviewed
regarding the 20*F EDG room design temperature decrease and the resultant impact on
the piping stress analysis, the EDG silencer supports, and the compressed air receivers.
(Section E2.1)
. . The licensee has a process in place to control the OE backlog and appears to be on i
track in reducing the number of open OEs, expecting to have 5-10 open OEs at the end
of RFO 12. (Section E2.1)
. The licensee identified several instances of noncompliance with technical specifications
and design requirements. These issues were properly captured into the licensee's
corrective action program and reported as LERs. Effective corrective action was taken
to resolve these issues. These issues are being treated as Non-Cited Violations (NCVs)
consistent with Appendix C of the NRC Enforcement Policy. The NCVs involved: (1) the
failure to have sufficient diesel fuel oil supply on-site, (2) inoperable reactor build:ng
closed cooling water alternative shutdown panel, and (3) inoperable control room high
efficiency air filtration system. (Section E8)
Plant Sucoort
. Radiological controls were effectively implemented for RFO12 as evidenced by close
health physics oversight of work and improvements in radiological controls implemented
for drywell work including assignment of a drywell radiological controls coordinator,
installation of permanent shielding, and use of video monitoring. (Section R1)
. An opportunity for improving radiological controls for access to upper drywell elevations
during movement of irradiated core components was identified and licensee staff
responded quickly to improve program controls. (Section R1)
. The problem reporting system was effectively used to identify, evaluate, and resolve
radiological control deficiencies. (Section R7)
. The licensee was conducting security and safeguards activities in a manner that
protected health and safety in the area of access authorization and fitnes for duty.
(Section S1)
. The review of the licensee's audit program for security and safeguards activities
indicated that audits were comprehensive in scope and depth, that the audit findings
were reported to the appropriate level of management, and that.the program was being
properly administered. In addition, a review of documentation applicable to the self- ;
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Executive Summary (cont'd)
assessment program indicated that the program was being effectively implemented to
identify and resolve potential weaknesses. (Section S7)
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Response to the main transformer fire by fire brigade members was good; their
immediate response prevented any serious damage to the plant. The licensee properly
classified the event in accordance with emergency classification guidelines. (Section
M3.2)
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TABLE OF CONTENTS
~ EXEC UTIVE SUM MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .vi
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. OPERATION S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
O1 Conduct of 0perations m ..........e................................1
01.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
. 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 2
O2.1 Refueling Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
04- Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
04.1 Operations Tagging Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
05 Operator Train!ng and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
05.1 Pre-startup Training . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
. I I . MAI NT E NANC E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
M1.1 General Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . .. . . . . 6
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M1.2 Salt Service Water (SSW) Piping Repair . . . . . . . . . . . . . . . . . . . . . . . 8
M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . . . . 9
' M2.1 Deferred Work items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . 10
M3.1 Inservice inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
M3.2 Main Transformer Fire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
111. E NGI N E ERI NG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 13
E2.1 Operability and Engineering Evaluations . . . . . . . . . . . . . . . . . . . . . 13
E8 Miscellaneous Engineering lasues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
E8.1 Y2K Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
E8.2 ~ - (Closed) LER 50-293/97-17-01: SSW Temperatures Greater
Than Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
E8.3 (Closed) LER 50-293/98-21: Inadequate Fuel Supply for Emergency
Diesel Generators (EDGs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
E8.4 . (Closed) LER 50-293/98-23: Incorrect Wiring Modifications Affected
Reactor Building Closed Cooling Water (RBCCW) Train *B" Altemate
Shutdown Panel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
E8.5 (Closed) LER 50-293/98-28: Control Room High Efficiency Air Filtration
(CRHEAF) System Relative Humidity Switches inoperable . . . . . . . . 21
. E8.6 (Closed) LER 50-293/98-29: Intake Structure Indoor Air temperature
Less Than Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
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Table of Contents (cont'd)
IV. PLANT SUPPORT . . . . . . . . . . ..... .......................... . ....... . 22
R1 Radiological Protection and Chemistry (RP&C) Controls . .............. 22
R1.1 Radiological Controls for Refuel Outage No.12 (RFO12) . . . . . . . . . 22
R1.2 Drywell Upper Level Access Controls . . . . .. . . . . . . . . . . . . . . . . . . . . 24
R7 Quality Assurance in RWP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . . . . . . 26
S7 Quality Assurance (QA) in Security and Safeguards Activities. . . . . . . . . . . . 26
V. MANAGEM ENT M EETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
X1 Exit Meeting S umm ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
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ATTACHMENTS
Attachment 1 - Inspection Procedures Used
- Items Opened, Closed, and Updated
- List of Acronyms Used
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REPORT DETAILS
Summary of Plant Status
At the start this inspection period, the Pilgrim Nuclear Power Station (PNPS) operated at 80%
reactor power;'On May 7; 1999, operators shutdown and cooled down the reactor to cold .
shutdown conditions for commencement of RFO12. The outage was scheduled for 30 days; l
however, due to a problem with the main electrical transformer, the refueling outage was
extended to replace the transformer. The reactor remained shutdown at the end of this
inspection period. i
The licensee declared an Unusual Event on May 18,1999, due to an electrical fire in the main
transformer. Further details of this event are discussed in Section M3.2 of this report. l
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By letter No. 99-93, dated May 3,1999, the NRC approved the transfer of the Pilgrim operating
license from Boston Edison to Entergy Nuclear. The license transfer is scheduled to occur in
July 1999 after completing RFO12.
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1. OPERATIONS
01 Conduct of Operations'
01.1 General Comments (71707)
Operators competently performed a normal shutdown and cool down of the plant to
commence RFO12. During the outage, the protected train safety system concept was
used. Signs were hung on components in the field to alert personnel not to interfere with
protected train equipment. Good coordination was evident when operators placed the
fuel pool cooling system into the augmented fuel pool cooling mode. This evolution
required extensive coordination from several local stations in the field and in the control l
room. Lastly, a major safety system loop swap was well planned and completed during '
the outage.
The inspector attended several shift tumover briefings conducted by the off going )
nuclear watch engineer (NWE). The briefings were detailed and included the status of j
equipment availability and also reviewed new problem reports. The outage plan-of-the-
day included a listing of protected /available equipment. The plan was updated daily by
NWEs. :
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' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline.
Individual reports are not expected to adWess all outline topics.
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O2 Operational Status of Facilities and Equipment
O2.1 Refuelina Ooerations
a. Inspection Scope (71707. 80710)
The inspector observed portions of reactor fuel movements made during two fuel
shuffles. Observations were made locally on the refueling floor and remotely in the
control room. The inspector also observed other portions of refueling activities from the
' refueling floor.
b. Observations and Findinos
Contract fuel handlers were used under the direct supervision of a licensed BEC Energy
senior reactor operator (SRO). The refueling bridge crew consisted of 2 contract fuel
handlers, a SRO and a reactor engineer. The inspector observed that fuel bundles were
moved in a diligent manner with no mishaps. The fuel movement plan was carefully
followed and several independent verifications were made to ensure that the proper fuel
- bundle was selected and moved to the correct location with proper bundle orientation..
Effective communication and teamwork was observed between contract and licensee -
personnel. Independent reviews of fuel moves were performed by the SRO, reactor
engineer and also by the control room operators who were in direct communication with . j
the refueling bridge personnel. No problems were identified by the inspector. l
Operators acted conservatively and demonstrated a proper nuclear safety focus by l
stopping fuel movement when anomalies arose. For example, operators stopped fuel
movement when the reactor cavity water clarity degraded to the point where the fuel I
bundle ball handle serial numbers could not be read. The issue of poor reactor cavity
water quality is further discussed in Section R1.1 of this report. Also, fuel movement was
stopped when the 905-panel reactor operator in the control room identified that one
source range monitor was operating erratically. The licensee revised the fuel transfer
plan to allow fuel movement to continue in the unaffected core quadrants per the plant H
technical specifications. The inspector determined that operators acted promptly to 1
identify and resolve degraded conditions during the fuel handling activities.
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Foreign material exclusion (FME) controls were observed to be in effect during refueling
operations. A dedicated FME watch was established on the refueling floor with a
- logbook to account for all tools and materials. - The inspector reviewed the log, which
was maintained up-to-date and no problems were identified. During in-vessel
inspections, some foreign material was found in the annulas region of the vessel. This
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material was subsequently removed by the refueling crew. The licensee determined
. that this material had been introduced into the core during a previous refueling outage.
Lastly, the inspector confirmed that senior licensee managers periodically toured the
. _ . _. refueling floor to provide management oversight of refueling activities. .
After fuel movement and core verification activities were completed, the inspector
- performed an independent verification of the location of 280 fuel bundles. This was
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done by viewing the core verification videotape and comparing each bundle to the cycle
13 core map to ensure correct location and orientation. Additionally, the inspector
confirmed the accuracy of the core map by verifying the map against the Fuel Cycle 13
~ Management Report prepared by the General Electric Company. . The inspector noted
that effective communication techniques were used between the reactor engineer and
contract fuel handlers during the core verification process. The inspector independently
determined that all 280 fuel bundles reviewed were located in the correct core location
with the proper orientation.
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_ The licensee used a new camera angle during the core verification to ensure that all fuel
bundles were properly seated. During the inspection, the licensee identified that the fuel {
bundles in cell 26-03 appeared to be 3/4 inch higher than adjacent bundles. The !
licensee documented this anomaly and initiated corrective actions. The four fuel bundles
were removed and the associated fuel support piece repositioned. The four fuel bundles
were reloaded but visual inspection revealed that the bundles were still sitting
approximately % inch higher than adjacent bundles. The licensee contracted the l
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- General Electric Company to perform an analysis to accept the condition as-is. The
inspector was informed by the reactor engineering supervisor that an engineering
evaluation would be completed prior to restart to confirm that this condition was
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acceptable. The inspector determined that the licensee performed well by using a new
camera angle to assure that all fuel bundles were properly seated.
Portions of other refueling work was also observed. The licensee developed a special
procedure to evaluate the condition of control rod 02-23 since this rod could not be
moved and remained inserted during most of the previous operating cycle. After
unloading the fuel bundles surrounding control rod 02-23, the licensee used remote
cameras to inspect the control rod drive for any anomalous conditions. The licensee
identified a small cap screw which was wedged between the control rod guide and index
tubes. The inspector observed the refueling crew retrieve this cap screw using a remote,
air-operated pair of pliers. The licensee could not identify the origin of the cap screw.
As a precautionary measure, the licensee replaced this control rod drive later in the
outage during the control rod drive change-out window.
c. Conclusions
Reactor fuel movements were performed in a controlled manner with effective
communications between contract fuel handlers, reactor engineers, control room
operators and the SRO stationed on the refueling bridge.
Operators stopped fuel movements when necessary to resolve degraded conditions l
such as poor reactor water quality and also when a source range monitor started to read
erratically. This reflected a conservative nuclear safety approach by operations
personnel.
A new camera angle during core verification revealed a fuel support piece which was not
fully seated. Also, a cap screw was removed from a control rod drive which had jammed
the rod during the previous operating cycle. Good FME practices were observed during
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refueling activities. Refueling activities were conducted in a controlled manner with
overall good performance.
04 ' - Operator Knowledge and Performance
04.1 Operations Tanoina Problems
a.~ Insoection Scope (71707.93702)
A review was performed of the problem extent and effectiveness of corrective actions -
initiated by the licensee to address several tagging errors which occurred during RFO12.
In each case, the licensee identified the problem and initiated a problem report to
document and evaluate the condition.
b. Observations and Findinos -
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, - The first . tagging event involved a temporary electrical power panel breaker that was to
be danger tagged open but was found with the danger tag on the floor and the breaker
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closed. This problem was discovered by the licensee on May 10,1999. The licensee -
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' initiated PR 99.9190 to document and evaluate this tagging discrepancy and held a -
critique. The subject temporary power panel breaker was non safety-related and did not
feed any loads, so there was no adverse safety consequence. At the end of this
. inspection period, the licensee's root cauw of this event was unknown.
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A second tagging event occurred on May 15,1999, when an operator identified that two
feed water system block valves were danger tagged open but the valves were required
to be shut. Operations personnel initiated PR 99.1121 to document and evaluate this
tagging discrepancy. No adverse safety consequence resulted from this tagging error.
The licensee determined that the apparent cause was over-confidence by the operator
who hung the tags. Since these valves were non safety-related, no independent verifer
was required to verify the implementation of the tagout.-
'A third tagging event involved several danger tags which were found hung on the ]
incorrect hydraulic control unit (HCU). Tags were found hung on HCU 42-47 vice 42-27.
The tags were hung on May 17,1999. Operations personnel initiated PR 99.9264 to
document and review this event. The licensee determined that the apparent cause of
this event was misjudgement - spatial mis-orientation by the operators who hung and
verified the tags. No adverse safety consequence resulted from this event.
A fourth tagging event occurred on May 27,1999, when two licensed operators removed
the wrong core spray system electrical fuses. Fuse 10A-F2B was removed vice 14A-
F28. This was identdied by an electrical lab engineer performing a walkdown of the
tagout prior to starting physical work. PR 99.1414 was initiated to document and
+ -- _ evaluate this tagging event.' No adverse safety consequence resulted from pulling and
tagging the wrong fuses. The licensee determined that the preliminary root cause of this
event was inattention to' detail - unawareness. The operators focused only on the fuse
designation F2B rather than the full fuse identification number 14A-F28.
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Collectively, these tagging errors constitute a violation of procedure 1.4.5, " Tagging
Procedure." The licensee identified each deficiency and initiated problem reports to
document, evaluate and correct each problem through the corrective action process.
- -This severity level IV violation of procedure 1.4.5 is being treated as a Non-Cited
Violation , consistent with Appendix C of the NRC Enforcement Policy. This is in the
licensee's corrective action program as prs 99.9190,99.1121,99.9264, and 99.9914
(NCV 50-293/99-03-01).
As a result of these tagging errors, operations management stopped all tagging
evolutions and convened a standown with all operators. Severalinterim corrective
actions were implemented to improve tagging performance. A pre-evolutionary briefing
will be held for every tagout. Tagouts that involve fuses will be completed by having two
operators identify and pull the fuses and an independent verification done at a different
time. - All HCU tagouts will have a peer check so that two operators hang the tags and an
independent verification will be done at a later time. Also, at the start of each shift, the
operations tagging lead will meet with the operations production manager to discuss
L significant tagouts to be worked during the shift. Also, operations management will
provide 100% oversight during the tagging evolution. The inspector determined that
these interim actions were a reasonable effort to improve tagging performance in the
short term.
The inspector noted that these tagging errors occurred early during RFO12 when the
tagging workload was the highest. Although the operators involved commented that
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there was no adverse production pressure while establishing the tagouts, on several
occasions the flow of work hanging tags was interrupted to support other activities. In
one instance, one operator was left to hang over 100 tags by himself on the HCUs. The
Operations Manager indicated that one of the tagging problem reports had been
upgraded to a significant condition adverse to quality (SCAQ) which required a full root
cause evaluation. Further, the manager indicated that the underlying causes would be
examined such as better management oversight and application of resources to support
' tagging evolutions. Lastly, the inspector noted that the Operations Manager had not
previously tracked any specific tagging performance indicators such as the number of
performance - related tag changes.
c. Conclusions
Several tagging errors resulted due to license operator errors both while hanging and
verifying checking tags. These errors occurred early in RFO12 during the highest
demand period for work release indicating that more effective shift (i.e., NWE and NOS)
and operations department management involvement was needed in the oversight and
scheduling of tagouts. Interim corrective actions were implemented to improve future
tagging performance,
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05 Operator Training and Qualification
05.1 Pre-startuo Trainina
a. Insoection Scope (71707)
The inspector attended the plant design change / pre-startup training session held on
June 2,1999. The training focused on modifications implemented during RFO12.
b. Qhgervations and Findinos
. As part of the licensed operator continuing training program, operations department
personnel were trained on modifications implemented during the cycle refueling outage.
Training included classroom and simulator training. The training covered 15 objectives
including modifications: cycle 13 core design, feedwater regulation valves retrofit and
degraded grid voltage protection system.
' An instruction module was provided to all attendees. It included a description of the
modification, applicable procedures, and drawings. The inspector noted that there was
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good interaction between the instructor and the licensed operators. As a result of some
confusion regarding the modification to the feedwater regulation valve retrofit, the )
Operations Department Manager required that job performance measure training be
included to demonstrate proper operation of how to lock up the valve. The inspector
verified that all operations department personnel were scheduled for the training.
c. Conclusions
Training provided to licensed operators on modifications implemented during the cycle
12 refueling outage was determined to be good. Simulator and job performance
measures were used, as necessary, to ensure operators could properly operate the
equipment and that they understood the modifications.
11. MAINTENANCE
M1 Conduct of Maintenance
M1.1 General Maintenance and Surveillance
a. inspection Scope (61726)
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The inspector observed portions of selected surveillance and maintenance activities to
verify use of approved procedures, correct system restoration, and proper post work l
testing. The following activities were observed: i
8.7.1.5 Local Leak Rate Test of Primary Containment Penetrations, Isolation
Valves, and Inspection of Containment Structure
8.5.2.7 Hydrodynamic Test for Measuring Leakage Through RHR System, Valve
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MO-1001-68B
8.M 3-1 Special Test for Automatic ECCS Load Sequencing of Diesels and
Shutdown Transformer with Simulated Loss of Off-Site Power
E9800005 . Replace RHR Valve MO-1001-68B
b. Observations and Findinas
The inspector verified that surveillance activities (procedures 8.7.1.5 and 8.5.2.7)
appropriately implemented technical specification (TS) surveillance requirements. Good
procedure adherence was displayed by the maintenance craft for work activities
observed. : Test engineers were noted directing surveillance activities with oversight
provided by quality assurance department personnel.
Portions of the reactor vessel disassembly and reassembly were observed by the
inspector. Overall, the inspector observed excellent performance by the refueling crew
which included the use of contractor workers. The reactor vessel stud tensioners !
worked much more reliably than during RFO10 and RFO11. Some new initiatives
worked well including the use of electronic shift logs and kevlar lifting slings for heavy
lifts. The new slings were much lighter and easier for the workers to set-up and handle.
Also, a new outage control center was established shortly prior to RFO12 in the O&M
building adjacent to the control room annex area.
A new effort during RF012 was to use mixed work teams composed of a plant
~ maintenance worker with a contractor worker. The inspector observed the positive effect ,
of this concept during some electrical breaker maintenance. Work was effectively '
planned and executed for the DC panel replacement project, the control rod drive
mechanism (CRDM) replacement activity and also during motor operated valve testing l
activities.
The inspector entered the steam tunnel on several occasions and observed
maintenance on the 2A main steam isolation valve (MSIV). The inspector observed !
metal filings in the valve body from the machining work of the seating surfaces. i
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However, a pressure plug was installed in the valve body ports and workers indicated the
filings would be removed prior to valve re-assembly. The welders experienced some
difficulty in performing weld repairs on the stellite guide ribs but eventually resolved the
problem. Lastly, rework was required when a replacement source range monitor (SRM)
did not function properly and had to be replaced. This rework resulted in additional
radiation dose since the work area was under the reactor vessel in the drywell. The
licensee initiated a review to determine why the replacement SRM did not function
property. Preliminarily, the in:ensee determined that the SRM detector may have been
damaged when being transferred to the job site.
During hydrodynamic testing of valve MO-1001-68B, the test pressure could not be
r - achieved due to leckage past the valve. The licensee issued problem report PR 99.9236
to document the problem. Valve MO-1001-68B was cut out and a new valve welded
back into the system. The inspector reviewed the post work test for this activity. The
licensee tested the valve in accordance with ASME code case N-416-1, "Altemate
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Pressure Test Requirement for Welded Repairs or installation of Replacement items by
Welding Class 1,2 and 3, Section X1, Division 1." The inspector verified that this code
. case was approved for use at the Pilgrim station and that the valve tested satisfactorily.
The pre-job brief for surveillance 8.M.3-1 was determined to be detailed; test terminati&
criteria, expected plant conditions, abort criteria, and personnel responsibilities were
clearly communicated. During review of the initial conditions prior to the performance of
the surveillance, the inspector identified that low pressure coolant injection (LPCI) throttle
vc've MO-1001-288 was not open. The residual heat removal (RHR) system was
required to be aligned for LPCI mode (that requires that the LPCI injection valve be open
and its breaker closed) per step 3(c) attachment 1 of the procedure. The throttle valve
was subsequently opened and the test commenced. Problem report 99.1647_was
written to document this condition.
The failure to position valve MO-1001-28B open per step 3(c) of precedure C.M.3-1 is a
violation of technical specification 6.8.A. This Severity Level IV violation is being treated
y as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy.
This violation is in the licensee's corrective action program as PR 99.1647 (NCV 50-
293/99 03-02).
c. Conclusions
Pre-job briefs for surveillance activities were determined to be good with proper oversight
- provided by the test engineer and quality assurance personnel.
Post work testing for observed maintenance activities was determiried to be good and in
accordance with code requirements.
Several procedure usage problems were identified by the licensee and the inspector. ;
One problem dealt with the positioning of LPCI throttle valve MO-1001-28B during
perfornsnee of the EDG load sequence test.
M1.2 Salt Service Water (SSW) Poina Repair
a. Insoection Scoos (61726)
The inspector otuerved portions of the replacement of the SSW discharge piping and
reviewed the circumstances surrounding the damage to two electrical conduits and a
potable water line during excavation of the SSW piping.
b. Observations and FindingE
The licensee performed an inspection of the SSW system during RFO12 and identified
p anat the discharge piping from the auxiliary bay to the discharge canal was degraded.
The degradation was the result of the inner pipe rubber lining becoming loose causing i
the carbon piping to be exposed to seawater, resulting in significant corrosive wall I
thinning. The rubber loss extended from the bottom dead center circumferentially up I
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each side about 45 degrees for a length of about 50 feet. Problem report (PR) 99.9207
was written to document this condition.
< u The licensee performed an engineering evaluation and concluded that the piping was
structurally adequate to maintain its integrity under combined pipe weight plus soil -
loading. The licensee concluded that the SSW discharge piping was oparable for decay
heat removal and refueling operations. To facilitate the replacement of tne SSW piping,
the licensee performed a temporary modification and installed temporary SSW piping to
allow repair of the buried piping.
The inspector reviewed the licensee'n engineering evaluation and concluded that it was
technically adequate and identified no discrepancies. A review of the installation of the
temporary SSW piping and the subsequent testing revealed that it was properly
implemented.
During excavation of the SSW piping, two electrical conduits and a three inch potable
. water line that supply the shore front were damaged. A review of the circumstances
leading to the event revealed that the licensee's site drawing for this location had
insufficient detail nor was it drawn to scale. The site characterization map failed to show
the water line or the conduits traversing the excavation site. The licensee had performed
ground penetration radar of the area and identified an indication traversing the
excavation area and modified the site drawing. However, when the licensee overlayed
the radar map on the site map they did not have exact reference points resulting in the ,
> drawing being slightly offset. The licensee modified the site drawing and excavated the
SSW piping with no further problems. The inspector considered the licensee's corrective
action adequate to address this issue.
c. Conclusions
The emergent replacement of the underground SSW discharge piping was well planned
and executed.
M2 Maintenance and Material Condition of Fadities and Equipment
M2.1 Deferred Work items
a. Insoechon Scope (62707)
The inspector reviewed changes made to the outage work scope. Emphasis was placed
on those work items that were removed or deferred from the scope of the cycle 12
refueling outage to determine the effect or, safety system performance and consictency
with regulatory commitments.
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b. Observations and Findinas
Changes to the outage work scope are reviewed by the outage review board (ORB).
1.The requested changes to the outage scope are documented on a Task Identification
and Change (TIC) form per procedure 3.M.1-46, " Outage Planning." The inspector
attended several ORB meetings and verified that TIC items were discussed in sufficient
detail and that a quorum of ORB members were present when evaluating emergent work
and changes to the outage scope.
The inspector performed a preliminary review of all the TIC items, a total of 48, that were
scheduled to be removed or deferred from the outage as of May 31,1999. Of those, the
inspector reviewed 16 of the more safety significant items with the Outage Manager to
better understand the issue and the basis for the recommendation. The inspector
concluded that the items removed form the outage should not adversely effect
equipment performance or overall system reliability.
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c. Conclusions
Deferred work items were property tracked and dispositioned by the outage review
boar J. No work items were removed from the outage scope that would adversely affect
safe plant operations.
M3 Maintenance Procedures and Documentation -
M3.1 Inservice insoection Activities
a. Insoection Scooe (73753)
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The inspectors reviewed the inservice inspection (ISI) activities that were pnt of
Refueling Outage (RFO) 12. The review encompassed witnessing nondestructive _
examination (NDE) activities in the plant, reviewing the qualifications of NDE personnel,
examining NDE procedures and the ISI program manual. Piping welds in sections of the
high pressure coolant injection (HPCI) system pioing were examined in the field and
compared tr: ihe piping weld diagrams and the = program manual. Additionally, the
inspectors assessed BEC Energy's oversight d cor, tractor supplied NDE services and
self assessment activities.
b. Observations and Findings
ISI Proaram Status
Pilgrim was implementing the 1989 edition of Section XI of the American Society for !
Mechanical Engineers (ASME) code. The unit was in the second period of its third ten-
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, , ~.-year interval, which began on July 1,1995. During this outage, Pilgrim began
implementing the containment inspection portion of Subsection lWE of the 1992
Addenda of the ASME Code. As required by the code, portions of the containment shell
+ hat could be susceptible to degradation had been identified and nondestructively
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examined.
The inspectors reviewed aspects of the containment inspection plan, and verified that it
l< included known problem areas where degradation (wall thinning) was likely to occur in
Mark I containment structures, i.e., at the torus waterline, the drywell sand cushion
< region, and upper drywell shell. At the time of the inspection, Pilgrim had not found
significant degradation.
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HPCI System Walkdown and Drawina Review
No deficiencies were identified during the field walkdown of the HPCI system. The HPCI
system weld isometric drawings accurately reflected the as-built configuration of the
- system. Further, the ISI program manual accurately described the location of welds on
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the HPCI system weld isometric drawings.
Observation of NDE Actnntieg
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l The inspectors witnessed portions of several NDE activities including an Ultrasonic (UT)
l _ examination performed by General Electric personnel on a recirculation system piping
l weld. The individuals who performed the examination met the train;ng and experience -
i requirements outlined in SNT-TC-1 A "Recommerided Practice, Personnel Qualification
and Certification of Non Destructive Testing."
l While observing the UT examinations, the inspectors verified the UT test equipment was
! calibrated in accordance with industry and BEC Energy standards and personnel were
examining the correct area. Further, the inspectors verified that deficiencies uncovered
during NDE activities were documsnted in the Pilgrim corrective action systems.
Oversicht and Self Assessment of NDE Activities .
During this outage, BEC Energy provided little oversight of vendor supplied NDE
activities in the field. Further, over the last two years, comprehensive reviews of the ISI
program had not been performed by Pilgrim personnel or an independent third party.
Although not an NRC requirement, it is common practice in the industry for utility
personnel, as part of an overall quality assurance program, to oversee some aspects of
vendor-supplied NDE services in the field and to perform periodic comprehensive
reviews of the ISI program. Nevertheless, it did not appear that the absence of such
reviews, has degraded the effectiveness of the Pilgrim ISI program.
c. Conclusions
BEC Energy was implementing inservice inspection activities in accordance with their ISI
program. NDE personnel were qualified, and adhered to procedures while performing
. . examinations. Deficiencies identified during inspection activities were properly
documented. HPCI system weld drawings accurately reflected the location of welds in
the plant.
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M3.2 - Main Transformer Fire
a. - Inspection Scooe (62707)
The inspector responded to the site for an unusual event on May 18,1999, involving a
fire in the main electrical transformer to assess the licensee's response to the event and
evaluate the effect to the plant.
b. Observations and Findinas
- On May 18,1999, at 6:32 p.m. a fire occurred at the Pilgrim Station in the main electrical
transformer. At the time of the event, the transformer was electrically isolated, with the
transformer oil drained to support maintenance and testing activities. The licensee had
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reolaced the "C" phase bushing of the main transformer and was in the process of
performing power factor and capacitance testing when smoke was observed coming
from the man-way hatch at the top of the unit. Testing was secured and the site fire
brigade notified. Shortly thereafter, the licensee requested off-site firefighting assistance
and declared an unusual event.
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The fire was characterized as " smoldering with no visible flames." Carbon dioxide and -
a small amount of water was used to suppress the fire. The fire was extinguished at
8:21 p.m., and the Unusual Event terminated at 9:25 p.m. The licensee stationed a
continuous fire watch to monitor for the possibility of a reflash. One minor injury
- occurred to a fire brigade member as a result of a static electrical shock, during use of a
carbon dioxide extinguisher.
The inspector responded to the site and monitored the licensee's response to Uc event.
Fire brigade members handled the incident well; the fire was immediately extiriguished
and there were no serious injuries. The fire had ;"., adverse effect on the plant other
than the immediate damage to the transformer. A detailed investigation revealed that the
- transformer needed to be replaced. The replacement of the transformer resulted in an
extension to the original refueling outage schedule. The inspector reviewed the
emergency classification guidelines and verified that the licensee properly classified and
reported the event.
Problem report PR 99.9231 was initiated to document and evaluate the cause of the fire.
The licensee's investigation revealed that the proper gap between the "C" phase bushing
and the main output lead was not established during testing. The gap was found to be
less than one inch. The exact cause of the fire is still under investigation; however, the
licensee postulated that the bushing and the lead were too close to remain electrically
isolated resulting in sparking and ignition of the oil soaked insulation material which j
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spread to adjacent equipment.
- _The testing was performed by contract personnel with oversight provided by a system
engineer. The inspector reviewed the test plan and identified that the post work test was
part of the maintenance request (MR) and provided little guidance. The MR installed and
tested the replacement bushing in accordance with the skill of the craft. There was no
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specific guidance listing the required gap to be established between the bushing and the
main output lead prior to doble testing. Discussions with the Electrical Engineering
Department Supervisor revealed that the theoretical gap required between the lead and 1
bushing to prevent spark-over was approximately one incl- -M the expected gap for )
testing was to be between 6 - 8 inches. A review of the car.;ue minutes revealed that
personnel conducting the test were aware of this requirement.
The inspector determined that marginal procedural guidance and/or human performance
errors resulted in the failure to establish the required gap between the bushing and the
main output lead resulting in the main transformer fire. The main transformer is a non
. safety-related component and is outside the scope of 10CFR 50 Appendix B, Quality
Assurance Criteria. As a result, no violations of NRC requirements were identified.
c. Conclusions
1
Response to the main transformer fire by fire brigade members was good; their
, immediate response prevented any serious damage to the plant. The licensee properly
classified the event in accordance with emergency classification guidelines. The failure l
to establish specific procedural guidance and human performance errors contributed to
the cause of the fire.
Ill. ENGINEERING
E2 Engineering Support of Facilities and Equipment
E2.1 Ooerability and Enaineerina Evaluations
a. Inspection Scope
The inspector reviewed a sample of the outstanding operability evaluations (OE) to
- ensure that guidance information and requirements, such as that included in the plant's
technical specifications, Generic Letter 91-18, and the updated final safety analysis j
report (UFSAR), were being followed Any applicable compensatory measures taken to i
assure operability were also included in the review. The sample included risk significant
issues associated with motor-operated valves in several systems and other equipment in
the emergency diesel generator (EDG), salt service water (SSW), and reactor building
closed cooling water (RBCCW) systems. The inspector also reviewed the status of BEC
Energy plans to reduce the OE backlog.
b. Observations and Findings
The !icensee performs OEs in accordance with Station Procedure No.1.3.34.5,
" Operability Evaluations." The procedure provides a systematic method for evaluating
- - degraded conditions that challenge the operability of safety-related systems, structures,
and components (SSC). An OE is usually supported by an engineering evaluation (EE)
which is prepared in accordance with Nuclear Engineering Services Group Procedure
No.16.04, " Preparing Engineering Evaluations." At .a meeting with the NRC in mid-April
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1999, the licensee discussed their plans to resolve about 70 OEs in the next several
months. About 5-10 OEs were expected to be open at the completion of RFO12. The
inspector's comments concerning specific OEs reviewed are presented below.
OE 98-052 - Excessive Head Loss in the Reactor Buildina Closed Coolina Water Pumo
Startuo Strainers
This OE was initiated in August 1998 to address a concern that excessive head loss in
the RBCCW pump startup strainers may reduce system flow rates below those assumed
in the containment heat removal analysis. This concem was identified in Problem Report
(PR) 98.9427. Pumps 202B through 202F had startup strainers installed while pump
202A has no strainer. Engineering reviewed the concem of PR 98.9427 and
recommended in EE 98-0072 that the RBCCW system should be considered operable
based on the following:
.
System operability provided an allowance for either pump degradation or
. increased system resistance (i.e., in this case pump startup strainers) of about
8 PSI. This information was supported by current containment heat removal and
the RBCCW syst9m hydraulic analyses, Calculations M-664 and M-770
respectively. No sources of debris were expected in the system to cause a
significant increase in strainer head loss from the current value due to normal or
post-accident operation.
. Pump net positive suction head (NPSH) requirements would be met since the
head tank normally provides about 120 feet of static head contributing to the
available NPSH whereas the pump required NPSH was no greater than 27 feet.
Compensatory actions were also recommended in engineering evaluatirin (EE) 98-0072.
Engineering recommended that suction strainer differentia! prets ;re should be
monitored periodically during normal operation using local suction pressure gage
' readings to ensure that the strainer pressure drop did not exceed 8 PSI. The licensee
indicated that this specific action was not implemented as it was optional. Since this was
a recommended and not a required compensatory action, accepted plant practice did not
require an Operations Review Commdee (ORC) review of EE 98-0072. But the
inspector observed that this practice was inconsistent with Nuclear Engineering Services
Group (NESG) Procedure No.16.04 " Preparing Engineering Evaluations," Revision 3,
Section 6.0 (4) which stated " engineering evaluations that recommend compensatory i
actions to ensure operability tequire ORC review." The licensee recognized Ns l
inconsistency with accepted plant practice and stated that NESG Procedure No.16.04
would be revised to change " recommend" to " require" accordingly. This procedure
problem was considered to be a minor violation of NRC requirements and not subject to
formal enforcement action. The licensee's actions to correct NESG Procedure No.16.04
were acceptable. j
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The licensee closed OE 98-052 on April 26,1999, on the basis that the startup strainers
had been removed from the 5 RBCCW pumps ("B" through "F"). The inspector verified
that the strainers were removed and spacer rings were installed to maintain the same
_. . flange spacing. The licensee confirmed that the condition of the startup strainers upon
removsl evidenced nothing unusual that would have invalidated any prior assumptions
and conclusions made in EE 98-0072. Maintenance request information was
appropriately noted on the OE 98-052 closeout form to indicate suction strainer removal
with one exception. The inspector noted that operations personnel inadvertently crnitted
documenting maintenance request 19801964 on the record copy of the OE 98-052
closeout form to substantiate that the startup strainer was removed from the "C" pump.
Tho system engineer verified that maintenance request 19801964 did accomplish
removal of the "C" pump startup strainer.
The inspector concluded that the closure of OE 98-052 was acceptable.
OE 98-057 - RBCCW System Discrepancies Imoactina Loss of Inventorv Procedure
After the review of an industry event related to the loss of inventory from safety related
closed loop ccoling water systems, the !!censee issued this OE in September 1998. The
licensee identified two discrepancies that required resolution:
. The chemical addition tanks were designated as non safety-related on the master
list of plant equipment and there were insufficient controls in Station Procedure
7.1.92, " Addition of Chemicals to the RBCCW, TBCCW, and Station Heating
Systems," to ensure they were in service for the minimum time required.
r The mechanical seals on the RBCCW pumps were also designated as non
safety-related on the master list of plant equipment, and insufficient inventory ,
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existed in the head tank to maintain RBCCW system operability during a
postulated catastrophic failure of one or more pump seals.
Resolution of the first discrepancy was accomplished by revising Station Procedure 1
7.1.92 to valve in the chemical addition tanks for 15 minutes when adding chemicals. l
The inspector verified that the procedure was changed to isolate the chemical addition j
tanks after this 15-minute period or if RBCCW system leakage might be encountered. '
The inspector considered this discrepancy to be resolved.
The licensee evaluated the second discrepancy in EE 98-0075 and concluded that the
currently installed seals were operable based on their in-service performance (i e.,
excellent service and reliability since 1992) and the accessibility of the components for
visual inspection and monitoring. For examplo, the most significant examination for a
mechanical seal applic& tion is the in-service leak test at normal operating pressure. The
pressure boundary parts of the seal are normally exposed to the system operating
m pressure. Operator tours lieve been sufficient for detecting unacceptable leakage. The
inapector considered this justification to be acceptable. The licensee intends to replace
the RBCCW pump mechanical seals with safety related material later in 1999 which will
enable closure of this OE.
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l- QE 98-058 - Undedicated Commercial Grade Material Installed in Safety Related Salt j
l Service Water System
l - , This OE was issued in September 1998 when the licensee determined that.some
l metallic parts (control rod plates, control rods, compression sleeves, nuts, and washer
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plates) of six expansion joints were received as commercial grade material and had not -
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been properly dedicated for safety related use prior to installation into the salt service .
water (SSW) system. The licensee considered the expansion joints to be operable
j based on EE 98-042. Discussion with the expansion joint supplier indicated that the -
! metallic parts were manufactured from ASTM A-36 carbon steel material. The licensee j
determined that the maximum pipe movements expected in the affected SSW piping ]
were less than the range of the expansion joints (i.e., gaps are provided on the control j
rods to accommodate a range of allowable motion). Therefore, the licensee expected
the loading on the expansion joint metallic parts to be within me limits of the A-36 4
l specification and took actions to confirm that the material was consistent with A-36 l
composition and properties.
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The inspector verified that the licensee completed appropriate material testing for the in-
plant material. Mass spectrometry tests were performed at several affected expansion .
Joints in the SSW pump house. The test results indicated a carbon content that matched
l to A-36 material. Hardnets tests were performed on a spare expansion joint (procured
t similar to the installed expansion joints) located in the warehouse and the mechanical
properties compared favorably to A-36 material.
The inspector noted that modification FRN98-01-37 was scheduled to be implemented
during RF012 to enable close out of OE 98-058 by installing expansion joints with fully
qualified material. The inspector concluded that the licensee's actions concerning OE 98-
058 were acceptable.
OE 98-013 - Emeroency Diesel Genarator Ambient Air Temoerature Low
This OE was issued to address the concem regarding overall engine temperature while
the emergency diesel generator (EDG) is in a standby status and the effect that this
temperature has on the EDG ability to start and accept initial load. OE 98-013 was
issued in March 1998 and was supported by EE 97-066, Rev. 2. Technicaljustification
was presented to support EDG operability provided that:
. Temperature (Outside) > (-) 20*F, and Temperature (Room)1> 40*F
The licensee's justification was technically sound and well supported by the EDG vendor ;
information.
The licensee intends to implement a plant modification (documentation only), Plant
. _ Design Change (PDC) No. 99-09, " Decrease of the EDG Building Low. Ten perature
Design Limit," to permanently change the EDG room desgn temperature (lower limit)
from 60*F to 40*F. The licensee indicated that this modification probably would not be
comp'eted until after restart from RFO 12. The inspector provided a comment which l
challenged the comprehensiveness of the scope of PDC 99-09 and its associated
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Calculation M893. It was not apparent that structural considerations would be reviewed
regarding the 20*F EDG room design temperature decrease and the resultant impact on
existing piping stress analysis, EDG silencer supports and movement, and possible
,~ .- impact of low temperature / brittle fracture on the compressed airJeceiver pressure
vessels. The licensee agreed to consider these considerations in the final development
of PDC 99-09. The inspector considered this comment to be a weakness in the
engineering work completed so far in support of PDC 99-09.
NIOV Operability Evaluations
The inspector reviewed eight operability evaluations related to motor-operated valves
(MOVs). While design margins were reduced in each case, the MOVs remained capable
of performing their design-basis functions either when some of the conservatism inherent
in the design calculations was removed or the results of dynamic tests were credited.
The evaluations and corrective actions were consistent with the licensee's commitments
1
made in response to Generic Letter 96-05, " Periodic Verification of Design-Basis
Capability of Safety-Related Motor-Operated Valves." The operability evaluatiens are
summarized below:
= OE 97-09: The minimum motor control center (MCC) voltages of high
pressure coolant injection (HPCI) torus suction valves MO2301-35
and MO2301-36 were calculated incorrectly using generic locked I
rotor currents. However, using motor-specific locked rotor curent
values, the motors still develop adequate output torque for the
valves to perform their safety functions under degraded voltage
conditions.
. OE 97-10: New, slightly higher calculated peak accident drywtil ambient
temperature resulted in a small decrease in the minimum available :
motor output torque of containment isolation valves M01301-16, 1
MO1001-50, and MO220-1 Valve operability was based on the
fact that (1) the MOVs are called upon to operate prior to reaching
peak design temperature, (2) motor winding heatup significantly
. lags the ambient temperature increase, (3) the methodology used
to derate the motors discounts the increased motor terminal
voltage due to higher winding temperature, and (4) the entire
motor cable lengths are not exposed to peak accident
temperature.
. OE 97-13: New undervoltage calculations reduced the available motor output
' torques of six direct current MOVs, raising the potential that
available torque would be insufficient to trip the torque switches.
However, valve testing showed that sufficient torque would exist to I
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actuate the switches. Also, the licensee demonstrated that low
pressure coolant injection (LPCl} valve MO1001-29A still had .
adegaate design ma gin after increasing the design valve factor 1
from 0.5 to 0.62.
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. OE 97-14: Under high design ambient temperature conditions, reactor core l
isolation cooling steam admission valve MO1301-61 may not i
develop enough torque to trip the torque switch. The licensee
calculated that sufficient motor output torque existed by reducing
generic motor output curve uncertainty from 15% to 5% on the
basis of motor-specific tests.
. OE 97-15: The valve factor of LPCI injection valve MO1001-29B was
increased due to reevaluation of dynamic test results. While
reduced, the valve's design margin remained adequate.
- OE 97-17: Reactor recirculation pump discharge valves MO220-5A/B had a
negative margin against the differential pressure (200 psid)
assumed to occur during a pump seal failure. The licensee
considered the differential pressure provided in the General
Electric Company design specification to be overly conservative.
Also, the plant accident analysis bounds any seal leakage that
would persist if the valves fail to close. Thus, isolation of the
recirculation pumps is not a safety-related function.
. OE 98-87: HPCI steam supply valve MO2301-3 did not indicate fully closed
during a dynamic test due to an increase in stem-to-stem nut
friction at flow isolation and torque switch trip. Also, the valve
experienced a sustained torque increase in the hammer-blow
region of the opening stroke. However, the valve does not have a
safety function to close under dynamic conditions and full flow
cutoff was achieved during the test. During the opening stroke, no
corresponding increase in thrust was measured in the hammer-
blow region, indicating that the motor was relieving the load stored
in the actuator's compensating spring pack. The valve's design
torque margin (about 20%) in the open direction was acceptable.
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. OE 98-79: Seven valves showed reduced or negative design margins when
thrust requirements were re-calculated using the Electric Power
Research Institute's performance prediction methodology (PPM).
BECo demonstrated that the valves remained operable by
removing some design conservatism regarding motor output
capability, stem friction coefficients and packing loads, and/or
design fluid conditions, or by taking cre'd for dynamic test results.
BECo is evaluating potential design changes to restore full design-
basis capability to these valves.
OE Backloa Reduction Plans
The inspector met with engineering and operations personnel who indicated that the OE
backlog reduction plans, which projected about 5-10 open OEs at the end of RFO 12, I
were still on schedule. The inspector noted that at least two additional OEs (plus the five
identified during a meeting with the NRC in Region i on April 15,1999) have been
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identified as very likely to remain open after restart. The first one, OE 98-013, "EDG Low
Ambient Air Temperature," was discussed above. A second OE could likely develop and
remain open to address a core spray pump NPSH problem associated with Problem
Report 99.9195 which was just identified on May 12,1999.
Notwithstanding these observations, the licensee appears to be generally on track to
close out the majority of OEs during RFO 12 and expects to have 5-10 OEs open prior to
restart. Operations and engineering meet at least monthly to review outstanding OEs
and a quartcrly report is issued to assure proper control of the OE backlog.
c. Conclusions
The inspector sampled about 10% of the 70 plus outstanding OEs. No major safety
cnneems were noted. Some minor problems were observed. These included attention- l
to-detail problems pertaining to the procedures governing operability and engineering
evaluations. Also, the preliminary engineering work supporting PDC 99-09 was not {
comprehensive in that structural considerations were not being reviewed regarding the
20*F EDG room design temperature decrease and the resultant impact on the piping
stress analysis, the EDG silencer supports, and the compressed air receivers. The
licensee was taking appropriate corrective actions to resolve thece problems.
BECo appeared to be ontrack in reducing the number of open OEs. At the end of RFO
12 BECo expected to have 5-10 open OEs, which would be comparable to that
discussed in a meeting with the NRC in Region I on April 15,1999. A process was in
place to control the OE backlog and BECo recognized the need to monitor this process
to achieve and maintain backlog goals. ]
E8 Miscellaneous Engineering issues
E8.1 Y2K Comoliance
The staff conducted an abbreviated review of Y2K : .tivities and documentation using j
Temporary Instruction 0 2515/141, " Review of Year 2000 (Y2K) Readiness of '
Computer Systems at f Jear Power Plants." The review addressed aspects of Y2K
management planning, documentation, implementation planning, initial assessment,
detailed assessmed, remediation activities, Y2K testing and validation, notification
activities, and contingency planning. The reviewers used NEl/NUSMG 97-07, " Nuclear
Utility Year 2000 Readiness," and NEl/NUSMG 98-07, " Nuclear Utility Year 2000
Readiness Contingency Planning," as the primary references for this review.
The results of this review will be combined with the results of other reviews in a summary
report to be issued by July 31,1999.
c - E8.2. JClosed) LER 50-293/97-17-01: SSW Temperatures Greater Than Desian
This LER supplement documents the need for additional net positive suction head
(NPSH) required for ECCS pumps which was greater than the licensing basis values.
LER 97-17 was originally reviewed end closed in NRC Inspection Report No. 50-293/98-
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09. Subsequently, the licensee submitted a request for a license change in letter no.
2.99.001, dated January 21,1999. This request was under review by NRR during this
inspection period. The need for additional over-pressure was due to a new debris
.
. ~ < analysis evaluation of the ECCS suction strainers located in the torus _The inspector
conducted an onsite review of this LER supplement and verified that the corrective
actions are being tracked by the licensee's corrective action program. The inspector
determined that this LER supplement met the intent 10 CFR 50.73. No problems were
identified. This LER supplement is closed.
E8.3 (Closed) LER 50-293/98-21: Inadeauste Fuel Suoolv for Emeroency Diesel Generators
(EDGs)
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This LER documents that the technical specitication minimum fuel requirement of
19,800 gallons for each EDG is insufficient to support the electrical loads specified in the
Updated Final Safety Analysis Report (UFSAR). The UFSAR specifies sufficient fuel be
available to support EDG operation for seven days. The licensee discovered a more i
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~ limiting fuel consumption case than had been included in the original design calculations,
indicating that assumptions used were non-conservative and inconsistent with those in
the UFSAR. Based on this case, the available EDG fuel could support operation of the
diesel for only four days at maximum loading. However, the licensee still considered the
EDGP perable based on how the loads would be operated udca the Pilgrim emergency
operat;ng procedures. Problem report PR98.9462 was written to document this condition
and to initiate corrective actions.
As corrective action, the licensee issued a standing order to notify the technical support
center to develop a fuel utilization strategy in the event of a LOOP coincident with a
LOCA. This would ensure that sufficient diesel fuel would be available to supply the
EDGs for a seven day period. Also, the licensee submitted a technical specificailon
amendment (to allow crediting the station blackout diesel fuel oil supply) to the NRC for
review in May 1999.
The inspector conducted an onsite review of the LER and verified that an operations
department standing order was issued, and that a technical specification i
amendment had been submitted to the NRC for review. The inspector questioned I
the licensee regarding whether preliminary calculations had been performed that I
demonstrate a fuel utilization strategy wou!d result in an adequate diesel fuel supply
for a seven day period and whether any specific guidance was provided to operators ;
ca what non-essential loads could be shed during an accident. In response to this ;
question, the licensee indicated that more specific guidance would be made i
available to operators.
The inadequate implementation of the requirement +3 have a seven day fuel supply
is a violation of design control requirements contained in 10CFR 50, Appendix B,
Criterion Ill. .This item was licensee-identified during its review of calculation '
adequacy as part of the design basis document initiative. The immediate and long
term corrective actions were comprehensive and either completed or appropriately
scheduled for completion in a reasonable time. This Severity Level IV violation is
being treated as a Non-Cited Violation consistent with Appendix C of the NRC ;
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Enforcement Policy. This violation is in the licensee's corrective action program as
PR 98.9462). (NCV 50-293/99-03-03). This LER is closed.
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E8.4 - . (Closed) LER 50-293/98-23: Incorrect Wirina Modifications Affected Reactor Buildina
_ Closed Coolina Water (RBCCW) Train "B" Attemate Shutdown Panel
This LER documented that the RBCCW train "B" attemate shutciown panel was
inoperable since 1992 due to a wiring error during the implementation of a modification.
The train "/' unel was correctly implemented and thus not affected. This condition was
identified b M licensee during troubleshooting of an indicating light not illuminated
(blown fuz; on the RBCCW train "B" alternate shutdown panel. Because of the
incorrect wiring the altemate fuse would not be switched intu the attemate shutdown
circuit during switching from the remote to local position. Problem report 98.9515 was ,
written to document this condition, and a drawing chage was issued and the licensee j
corrected the panel wiring to restore the system to an operable status. The licensee's <
extent review did not identify any slmilar problems.
The inspector conducted an onsite review of the LER and determined the corrective
actions were appropriate. The inspector verified that a drawing change was made and
that the wiring error was corrected. The incorrect implementation of an engineering
modification was considered a violation of NRC design control requirements. This
Severity Le' vel IV violation is being treated as a Non-Cited Violation consistent with
Appendir C of the NRC Enforcement Policy. This violation is in the licensee's corrective
action program as PR 98.9515 (NCV 50-293/99-03-04). This LER is closed.
E8.5 (Closed) LER 50-293/98-28: Control Room Hiah Efficiency Air Filtration (CRHEAF)
System Relative Humidity Switches Inoperable
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This LER documented that the CRHEAF system relative humidity switches were
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inoperable. As part of the design oasis information program the licensee performed a
set point calculation of the CRHEAF system. This revealed that the set point for i
statistical uncertainty was 25 percent. Applying this factor to recently performed and !
past surveillances would cause the relative humidity to exceed the technical specification I
value. The cause of the statistical uncertainty (instrument drift) was s+tributed to
degradation of the nylon filaments that are part of the humidity switch. Problem report
98.9621 was written to document this condition. As an immediate corrective action, the
licensee declared the CRHEAF system inoperable and performed a temporary
modification that results in heating coils to energize whenever the system is in placed in
operation.
The inspector conducted an onsite review of the LER and determined that the corrective
actions were apprcpriate. The inspector verified that the licensee properly irviemented
technical specification requirements and that the temporary modification was property
i- . . . . installed. The failure of the CRHEAF system humidity switches to mainiain the relative
humidity of the system below 70 porcent is a violation of TS 3.7.B.2. This Severity Level
IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the
NRC Enforcement Policy. This violation is in the licensee's corrective action program as
PR 98.9621 (NCV 50-29M99-03-05). This LER is closed.
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E8.6 (Closed) LER 50-293/98-29: Intake Structure Indoor Air temperature Less Than Dstian
This LER documents that the air temperature inside the intLke structure went below the
. - UFSAR specified design value of 60*F. Problem report 98.9644 was written to
document and evaluate this condition. This issue was previously documented and
reviewed in NRC Inspection Report 50-293/98-11, section 01.1. No violations of NRC
requirements were identified. This LER is closed.
IV. PLANT SUPPORT
R1 Radiological Protection and Chemistry (RP&C) Controls
R1.1 Radioloaical Controls for Refuel Outaae No.12 (RFO12)
a. Insoection Scope (83750)
A review was performed of radiological controls implemented for Pilgrim'.s cycle 12 refuel
outage. Information was gathered through tours of the plant; discussions with health
physics technicians and supervisors; evaluations of radiological boundaries; a review of-
high radiation area controls.; a review of the radiologically controlled area portal monitor
log; through reviews of rad:ation dose goals; and a review of radiological control
improvements implemented for drywell work.
b. Observations and Findinas
The radiological controls organization maintained cloae oversight of plant work as
evidenced by the presence of knowledgeable health physics technicians stationed at
major plant work areas inc'ading the radiologically controlled area red line, the drywell,
reactor building, fuel floor, and condenser bay.
Tours through the plant showed that radiological control boundaries were well defined
and clearly posted. Controls for high indiation area access included use of radiation
work permits (RWPs); use of alarming dosimetry; radiological postings; required use of
locked access controls or flashing lights for areas that could result in an individual
receiving a dose equivalent in excess of 1000 mrem per hour at 30 centimeters; and
increased health physics oversight and monitoring. Tours of the plant confirmed that
high radiation and locked high radiation areas were appropriately posted and doors that
were required to be locked were found locked or appropriately controlled by health
physics staff.
Direct observations of drywell work indicated that appropriate radiological controls were
implemented including use of radiation work permits, radiok'gica! pos, tings, constant
health physics oversight, health physics briefings, appropriate evaluations of working
. conditions including radiological surveys, and use of alarming dosimetry.
Direct observations of controls implemented for the removal of a potentially highly
irradiated 3/4 inch cap screw from control rod drive tube cell 02-23 in the reactor cavity
indicated that appropriate radiological surveys were taken to ensure that removal of the
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cap screw from the water did not present a radiation hazard and appropriate controls
were taken to prevent the spread of contamination.
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. Direct observations of work performed at the condenser bay. indicated that appropriate
controls were taken to protect personnel from contamination including use of radiation
work permits, radiological postings, and use of protective clothing.
Radiation Dose Goals
Radiation dose goals were established and tracked for major outage work. The station
radiation dose goal for RFO12 was set at 310 person-rem and included 28 person-rem
for minor electrical and mechanical maintenance,27 person-rem for main steam isolation
valve work (MSIV),17 person-rem for reactor pressure vessel nozzle work,16 persom
rem for control rod drive replacement,16 person-rem for motor operated valve work,
12 person-rem for drywell shielding, and 9 person rem for torus diving and desludging
activities. Dose estimates were used as the basis for radiological planning, and
performance versas dose-goals were routinely tracked and frequently communicated to
plant staff.
Drvwell lmorovements
Drywell work presented a significant challenge to the radiological controls staff due to
elevated dose rates on reactor water re-circulation piping, core spay piping, reactor
water cleanup piping, and residual heat removal (RHR) piping. Approximately 68
percent of projected station dose (212 person-rem) was estimated to be received
performing drywell work. Radiological survey results showed that typical dose rates on ,
reactor veseel nozzles ranged from 1000 - 2000 mrem per hour and the majority of 1
ad i co I di a or hat n o derto mi m e I ose, uit
work efficiency and dose reduction initiatives were implemented including the
assignment of a drywell radiological controls coordinator in advance of the outage,
development of a drywell improvement plan, installation of permanent shielding, _j
installation of video cameras for monitoring of key work areas; placement of a tool crib at j
the drywell entrance; use of cord stands to keep electrical cords and hoses off of !
walkways; use of scaffolding staging racks to minimize clutter; increased use of I
temporary lighting; use of a motorized hoist, and development of a Drywell Field Guide
for briefings. The drywell coordinator stated that accumulated personnel doses for
drywell work were below projected estimates.
Detectable Shoe Contaminations
A review of a portal monitor log located at the radiologically controlled area (RCA) egress
point (red line) indicated that during a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period from the moming of May 18,1999,
- to May _19,.1999, there were approximately 175 occurrences in which some level of
contamination was detected on personnel shoes. The majority of shoe contaminations
were of very low activity with only ten exceeding the limit for documenting a personal
contamination report. None of the detected contaminations resulted in any measurable
personnel exposure. The radiation protection manager stated that additional
decontamination personnel would be assigned to wet-mop areas adjacent to
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contaminated area boundaries, that additional sticky pads would be placed in the plant to
minimize the spread of contamination, and a review of ventilation flow paths would be
initiated. Problem Report 99.1507 was subsequently generated to resolve the cause for
the condition.
RHR Shut Down Coolina Crud Burst
Licensee staff reported that " crud bursts" occurred when the A-loop and B-loop of
residual heat removal (RHR) shut down cooling systems were placed in-service.
Corrosion products including iron-59 and cobalt-60 were released into the reactor cavity,
the fuel pool cooling system, and the A and B-loops of the RHR system. This had the
immediate effect of clouding reactor cavity water which resulted in the temporary
suspension of in-vessel work and increasing radiation dose rates in the fuel pool
skimmer corridor and the RHF. A and B-Quads. The radiation protection manager stated
that due to the limited scope of outage work planned irt affected areas, the increases in
dose rates were not expected to significantly increase outage dose. The exact reasons
.
for the crud burst were not immediately known. Preliminary findings indicated that the
crud was a result of deposits in the dead legs of the RHR system from a recent chemical
decontamination. ' Details of the event were placed on the nucisar network, other plents
were contacted to evaluate similar occurrences, and a review of the impact of the crud
burst on plant systems and components was initiated.
c. Conclusions
Radiological controls were effectively implemented for Pilgrim's twelfth refuel outage
(RFO12) as evidenced by close health phytics oversight of work and improvements in
radiological controls for drywell work including assignment of a drywell radiological
controls coordinator, installation of permanent shielding, and use of video monitoring.
R1.2 Rocatell Uooer Level Access Controls
a. Insoection Scope (83750)
The potential exists for dose rates to increase in the upper elevations of the drywell if
irradiated fuel, irradiated core components, or equipment with the potential for elevated
dose rates such as underwater vacuums are dropped, placed on, or come in close
physical proximity to the cavity /drywell bulkhead. A review was performed of radiological
controls implemented to protect drywell workers during movement of irradiated fuel,
irrauisted core components, or equipment with elevated dose rates. Information was
gathered through interviews with cognizant personnel, tours through the drywell and fuel '
floor, and a review of the following documents:
. Procedure No. 6.1-009, " Radiological Controls for Handling Highly Activated
-Components and Underwater Equipment;"
- Procedure No. 4.3, " Fuel Handlir 3;" and
. RFO-12 Drywell Field Guide.
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- b. Observations and Findinas
Formal radiological controls for the movement of irradiated fuel were included in
a _
m Operations procedure PNPS 4.3, " Fuel Handling," and required the use of a bulkhead
shield (cattle shoot) for the movement of fuel between the cavity and the fuel pool and
stated that " Radiation Protection shall post access above 63' elevation in the drywell if -
fuel is handled." However, only informal programmatic controls were in-place to ensure
that drywell workers did not receive an unplanned exposure due to the movement of
irradiated core components or equipraent with the potential for elevated dose rates such
as underwater vacuums. Two examples were identified by the inspector which had the
potential for increasing dose rates in the upper elevations of the drywell:
. During refuel outage No.11 (RFO11) the core shroud tie-rod was moved from the
reactor cavity over the drywell bulkhead to the equipment pit. If this component
had been placed or accidentally dropped on the cavity /drywell bulkhead dose
rates could have increased in the upper elevation of the drywell.
. Three coerating underwater vacuums used to filter reactor cavity water were
observed to have been placed directly on the reactor cavity /drywell bulkhead. -
Placement of an operating underwater vacuum directly on the cavity /Drywell
bulkhead had the potential to increase dose rates in the upper elevations of the
drywell.
The radiation protection manager (RPM) acknowledged the opportunity for improvernent ,
and took the following actions to improve program controls: 1) four remote radiation
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monitors were placed in the upper elevation of the drywell to allow the health physics
staff to remotely monitor dose rates in the upper elevations of the drywell; 2) health
physics technicians assigned to the fuel floor and drywell were briefed on the potential ,
for increasing dose rates in the upper drywell during movement of components and '
equipment with elevated dose rates; 3) advice on procedural controls was solicited from
other sites, and 4) an action item was initiated to evaluate and implement formal program
controls. 1
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c. Conclusion
An opportunity for improving radiological controls for access to upper drywell elevations
during movement of irradiated core components was identified and licensee staff
responded quickly to improve program controls.
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R7 Quality Assurance in RWP&C Activities
a. Insoection Smoe (83750)
A review was performed of the use of the problem reporting system for.the identification
and resolution of radiological control deficiencies. Information was gathered through
selected reviews of problem reports and through discussions with cognizant personnel.
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b. Observations and Findinas
Deficien::ies and opportunities for improvement were placed into the problem reporting
m system for evaluation and resolution. A selected review showed that appropriate j
evaluations were performed and timely corrective and preventative actions were
implemented for identified deficiencies,
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c. Concluulons
The problem reporting system was effectively used to identify, evaluate, and resolve ,
radiological control deficiencies. j
S1 Conduct of Security and Safeguards Activities (81700)
a. Insoection Scoce (81700) ,
.. Determine whether the conduct of security and safeguards activities met the lictasee's
commitments in the NRC-approved security plan (the Plan) and NRC regulatory
requirements. The security program was inspected during the period of May 10-12,
1999. Areainspected: access authorization.
b. Observations and Findinae
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Access Authorization. A review of the access authorization (AA) program was l
conducted to verify that program implementation was in accordance with applicable {
regulatory requirements and Plan commitments. The review included an evaluation of 1
the effectiveness of the AA procedures, as implemented, and an examination of AA
records for several individuals. The AA program, as irnplemented, provided assurance
that persons granted unescorted access did not constitute an unreasonable risk to the
health and safety of the public. Additionally, a review of access denial records and
applicable procedures revealed that appropriate actions were taken when individuals
were denied access or had their access terminated. Those actions included the
availability of a formalized process that allowed the individuals the right to appeal the
licensee's decision. l
c. Conclusions
The licensee was conducting its security and safeguards activities in a manner that
protected public health and safety and that this portion of the program, as implamented,
met the licensee's commitments and NRC requirements.
S7 Quality Assurance (QA) in Security and Safeguards Activities (81700)
a. Insoection Scope l
The areas inspected included audits, problem analyses, corrective actions, and
effectiveness of management controls.
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b. Observations and Findinas
Audits. A review was conducted of the most recent physical security program audit and
-- the Fitness for Duty (FFD) audit. Both audits were found to have been conducted in
accordance with the plan and FFD rule. The audits were thorough and in depth, and the
audit teams included independent technical specialists. Findings from the audits were
not indicative of program weakness and implementation of the corrective actions for the
findings were generally to effect program enhancements.
Problem Analyses. A review of data derived from the security department's self-
assessment program indicated that potential weaknesses were being tracked, and
trended.
Corrective Actions. A review was conducted of the corrective actions implemented by
the licensee in response to both the QA audits and the self-assessment program. All
corrective actions had been implemented and tne corrective actions were effective.
Effectiveness of Mar.acement Controls. The licensee has programs in place for
identifying, analyzing and resolving problems. The programs included the performance
of annual QA audits, a departmental self-assessment program, and the use of industry 4
data, such as violations of regulatory requirements identified by NRC at other facilities,
as criterion for self-assessment,
c. Conclusions ,
1
Audits of the security program were comprehensive in scope and depth, and findings
were reported to the appropriate level of management. The self-assessment program
was effectively implemented to identify and resolve potential weaknesses.
V. MANAGEMENT MEETINGS
X1 Exit Meeting Summary 1
The inspector met with licensee representatives at the conclusion of the inspection on
June 29,1999. At that time, the purpose and scope of the inspection were reviewed,
and the preliminary findings were presented. The licensee acknowledged the
preliminary inspection findings.
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ATTACHMENT 1
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifylag, Resolving, and Preventing
Problems
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 81700: Physical Security Program for Power Reactors
IP 82301: Evaluatloa of Exercises for Power Reactors
IP 83750: Occupational Radiation Exposure
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92901: Followup- Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
' IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
Tl 2515/141 Y2K Readiness Review
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Attachment 1 2
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ITEMS OPENED, CLOSED, AND UPDATED
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Closed
l LER 50-293/97-17-01 SSW Temperatures Greater Than Design >
l LER 50-293/98-21 Inadequate Fuel Supply for Emergency Diesel Generators (EDGs) .
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LER 50-293/98-23 incorrect Wiring Modifications Affected Reactor Building Closed
Cooling Water (RBCCW) Train 'B' Altemate Shutdown Panel (
! LER 50-293/98-28 Control Room High Efficiency Air Filtration (CRHEAF) System
l Relative Humidity Switches inoperable
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. LER 50-293/98-29 Intake Structure Indoor Air temperature Less Than Design
NCV 50-293/99-03-01 - Tagging error
i NCV 50-293/99-03-02 The failure to position valve MO-1001-28B open per step 3(c) of
procedure 8.M.3-1
NCV 50-29/99-03-03 Inadequate Fuel Supply for Emergency Diesel Generators (EDGs)
NCV 50-293/99-03-04 Incorrect Wiring Modifications Affected Reactor Building Closed
Cooling Water (RBCCW) Train "B" Altemate Shutdown Panel
NCV 50-293/99-03-05 Control Room High Efficiency Air Filtration (CRHEAF) System
Relative Humidity Switches Inoperable
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Attachment 1 3
LIST OF ACRONYMS USED
<
CAS Central Aiarm Station
CCTV closed circuit television
CFR Code of Federal Regulations
CRHEAF Control Room High Efficiency Air Filtration
DRP Division of Reactor Projects
EDG Emergency Diesel Generator
FSAR Final Safety Analysis Report
IFl Inspection Follow-Up item
IR inspection Report
LCO Limiting Condition of Operation
LER Licensee Event Report
mrem millirem
MR Maintenance Request
MSIV Main Steam isolation Valve
NCV Non-Cited ' lolation
NOV Notice of Violation
NPO Nuclear Plant Operator
NRC Nuclear Regulatory Commission
NRR Office of Nuclear Reactor Regulation
PA protected area
PDR Public Document Room
PNPS Pilgrim Nuclear Power Station
PR Problem Report
PWT Post Work Test
QA quality assurance
RCA Radiologically Controlled Areas
RFO Refueling Outage
RP Radinlogical Protection j
RPM radiatan protection manager l
RWP radiatior work permit
-SAS Secondiry Alarm Station
SBC Station Blackout
SFM security force member .
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T&Q training and qualification
the Plan NRC-approved physical security plan
UFSAR Updated Final Safety Analysis Report
VIO Violation
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