ML20210S886
| ML20210S886 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 08/29/1997 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20210S864 | List: |
| References | |
| 50-245-97-202, 50-336-97-202, 50-423-97-202, NUDOCS 9709120179 | |
| Download: ML20210S886 (92) | |
See also: IR 05000245/1997202
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U.S. NUCLEAR REOULATORY COMMISSION
] OFFICE OF NUCLEAR REACTOR F.EGULATION
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8PECIAL PROJECTS OFFICE
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, Docket Nos.: 50 245 50 330 50 423
Report Nos.: 97 202 97 202 97 202
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License Nos.: DPR 21 DPR 65 NPF 49
Licensee: Northeast Nuclear Energy Company
P. O. Box 120
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Waterford, CT 06385
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Facility: Millstone Nuclear Power Station, Units 1,2, and 3
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Inspection at: Waterford, CT
Dates: May 20,1997 July 21,1997
- inspectors
- T. A. Easlick, Senior Resident inspector Unit 1
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D. P. Beaulleu, Senior Resident inspector, Unit 2
A. C. Corne, Senior Resident inspector, Unit 3
A. L. Burritt, Resident inspector, Unit 1
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R. J. Arrighi, Resident inspector, Unit 3 .
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J. W. Andersen, Project Manager, Unit 3
R. S. Bhatia, Reactor Engineer
J. E. Carrasco, Reactor Engineer
D. A. Dempsey, Reactor Engineer
1 J. T. Furia, Senior Radiation Specialist
I- L. M. Harrison, Reactor Engirieer
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J. H. Lusher, Health Physicist
D. T. Moy, Reactor Engineer
L. L. Scholl, Reactor EnD i neer
M. A Blamonte, NRR
R, Pelton, NRR
, M. Kotzalas, NRR
J. B. O'Brien, NRR
P. Berler, NRC Contractor
J. C. Higgins, NRC Contractor
S. M. Wong, NRC Contractor
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' Approved by: Jacque P. Durr, Chief
Inspections, Special Projects Office, NRR
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9709120179 970829
DR ADOCK 050002 5
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TABLE OECONTEN1B
E X EC UTlW S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
U1.1 Operations ..................................................1 l
U101 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 '
U 1.Il M ain t o n ' n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
U1 M3 Maintenance Procedures and Documentation ............... 5 :
U1 M8 Miscellaneous Maintenance lasues . . . . . . . . . . . . . . . . . . . . . . . 6
U 1 Ill E nginee ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
U1 El Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
U1 E3 Engineering Procedures and Documentation ................ 9
U2.1 Operations .................................................10
U2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 12 ,
U 2.ll M aint enanc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
U2 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 13
U 2.lli Enginee rin g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
U2 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 15
U3.1 Operations .................................................22 !
U3 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
U3 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . 24
U3 08 Miscellaneous Operations issues (92700) . . . . . . . . . . . . . . . . . 26 -
U 3.li M ainte nance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 9
U3 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
U3 M3 Maintenance Procedures and Documentation ..............34
U3 M4 Maintenance Staff Knowledge and Performance .......,,,,.41
U3 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 43
U 3.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 7
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U3 E2 Engineering Support of Facilities and Equipment ............ 47
U3 E3 Engineering Procedures and Documentation ............... 49 .
U3 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 57
IV Plant Support .................................................66
R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . 66
R5 Staff Training and Qualification in Radiological Protection and
Chemistry Controls ................................,69
P4 Staff Knowledge and Performance in Emergency Preparedness . . 69
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P8 Miscellaneous Emergency Preparedness issues . . . . . . . . . . . . . 74
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F1 Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . 74
F4 Fire Protection Staff Knowledge and Perforrnance . . . . . . . . . . . 70
F7 Quality Assurance in Fire Protection Activities . . . . . . . . . . . . . . 77
V. M an agement M ee ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 8
X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . 78
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EXECUTIVE SUMMARY
Millstone Nuclear Power Station
Combined Inspection 245/97 202; 336/97 202;423/97 202
Operations
- At Unit 1, recent changes within the operations department require the shif t
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managers to report to the assistant operations manager, a now reporting
requirement and a change from the previous responsibility of the assistant.
Following a review of the concerns raised by the inspector, operations management
has taken steps to ensure that the roles of the operations manager and the assistant
operation manager are clearly defined, including the new reporting structure.
(U1.01.2)
- During a review of the restoration process for the Unit 1 service water system, the
operations staff was not initially using a new operation departmentalinstruction,1-
OPS 0.32 " Millstone Unit 1 System Readiness Review," which would have
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enhanced the restoration by providing a formal process for returning a system to an
l operable or available status. Additionally, an Individual assigned as the overall
i management lead for the evolution did not function in that capacity. The reactor
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operator assigned to control and monitor the restoration activities from the control
room, did an excellent job coordinating the step by step activities with the field
operators, and kept the unit supervisor informed of each step of the restoration.
There was also good coordination between operations, the test engineer, and the
management test lead, The service water normal operating procedures did not
contain appropriate guidance fer determining normal system operating parameters
following the system restoration. (U1.01.3)
- Overall, operator performance at Unit 2 was good in evaluating shutdown risk by
maintaining awareness of plant conditions and equipment availability. In particular,
on July 14,1997, operators exhibited a good questioning attitude regardng the
planned removal from service of the spent fuel pool area ventilation supply f an.
(U2.01.1)
- At Unit 2, the licensee initiated effort in removing 10 non-conservative technical
specification clarifications from the technical requirements manual was good.
(U2.01.2)
- At Unit 2, the total backlog of 780 condition reports (CRs) that are greater than 120
days old indicates that timeliness for completing corrective actions continues to be a
concern. The new management planned to demonstrate a higher standard by
dispositioning newly generated CRs in a timely manner while establishing a plan for
working off the CR backlog that existed when they arrived. However, the backlog
of 200 CRs greater than 120 days old that were generated in 1997 indicates that
the new management is also ineffective in addressing the corrective action
timeliness issue which is considered a significant weakness. (U2.01.3)
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- At Unit 2, although the licensee determined that there would be sufficient net .
positive suction head available to the reactor building closed cooling water (RBCCW)
pumps, the f ailure to evaluate and proceduralize the level band that operators should
control RBCCW surge tank level was considered a weakness. (U2.03.1)
e Although the loss of spent fuel pool cooling at Unit 3 was not significant from a
de ign basis or safety related viewpoint, it was significant not only with respect to
the adequacy of current operational and configuration control but also
management's expectation for operational standards. The former appears to have
been addressed by the licensee's Event Review Team (ERT) report, while the latter
was in the process of being assessed at the close of this inspection period. The
NRC will continue to monitor the licensee's assessment of this event,its generic
implications on the adequacy of other programs, and the implementation of effective
corrective actions. (U3.01.1)
e At Unit 3 the Nuclear Oversight organization appeared to be actively involved in
quality assurance and assessment activities directed toward effective corrective
actions for identified problem areas and program enhancements to improve future
operations. The initiatives reviewed this period attest to a more active role by
Nuclear Oversight in dealing with line performance. However, while the routine OA
and oversight reports document cognizance of the areas which represent the most
significant challenges to Iruproving performance, the ability of Nuclear Oversight to
effect positive changes has not yet been fully demonstrated. (U3.07.1)
e NRC review of several LERs established that while the licensee's operational
activities were proper evolutions, literal compliance with the plant TS had not been
maintained. Based on the appropriate corrective actions and the low safety
significance of the issues, these licensee identified and corrected violations are
being treated as non cited violations. The closure of the LERs does not address the
generic concern for TS compliance. A review of LERs issued as of April 1996
revealed that there have been a number of LERs that have dealt with TS compliance
problems relating to questionabic interpretations. This area is of current interest for
further NRC review. (U3.08.1)
Maintenance
e A review was conducted of the preparation and planning activities associated with
the retrieval of a hatch bolt from the Unit 1 standby liquid control (SBLC) tank.
Nuclear oversight (performance evaluation (PE) group) became aware of the plans to
retrieve a hatch bolt from the SBLC tank and raised a number of questions
concerning the uen of an automated work order in place of a special procedure. The
lack of clear guidance on when a special procedure is required resulted in significant
resistance from the line personnel to PE concerns about using a work order to
perform the work. The decision was made by plant management to develop a
special procedure for the bolt retrieval. (U1.M3.1)
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l. * At Unit 1, the licensee's corrective actions were appropriate to address concerns
with the adequacy of procedural guidelines for determining quality control
involvement in safety related work activities. This closes a previous unresolved
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item concerning this issue. As feedback to the package development process, the
- open item package had most of the requisite information. -(U1.M8.1) -
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e Contrary to Unit 2 technical specifications, during preparations for a surveillance,
operators mistakenly aligned all three high pressure injections to the reactor cooiant
system. This licensee identified concern was characterized as a non cited violation.
(U2.M8.2)
e A comprehensive self assessment of the Millstone 3 IST program documented broad
scope problems that constituted a violation of 10 CFR 50.55alf). The licensee-
- identified violation was not cited because the causes for the program f ailures were
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being addressed adequately, and individual test discrepaneles were being tracked
and resolved appropriately.- (U3.M1.2)
- The_ Unit 3 pressurizer safety / relief valves and main steam safety valves were tested
-In accordance with Code requirements. A followup item was opened regarding the
potential that relief valve testing to the valve " simmer" point may be
, nonconservative. For other Code Class 2 and 3 relief valves, set pressure
adjustments made to account for differences in bench test and normal operating
ambient temperatures need to be justified by test per OM 1 (U3.M3.1)
e Unit 3 acceptance criteria established for IST of safety related pumps met or I
exceeded Code requirements. Equipmerit or procedure changeu will be needed to
meet Code requirements for repentability of test reference values, or NRC relief to
use broader tolerance bands will be needed. (U3.M3.2)
e The Unit 3 power operated valve exercise tests met or exceeded Code
requirements, and use of the motor power monitor diagnostic system was
commendable. Nonintrusive testing of check valves also was noteworthy, but more
documentation was needed to meet GL 89-04 requirements. Additional manual
valves may need to be added to the IST program, even if their safety functions are
passive. (U3.M3.3)
e A review of ARCOR coating application work orders revealed that on six separate
occasions the recoat window was exceeded. The collective procedural
noncompliance indicates both an individual and departmental control performance
problem in that it demonstrates a low standard for following procedures and a lack
of management oversight for this critical evolution. This f ailure to follow procedures
is a violation of technical specifications. (U3.M1.4)
e An apparent violation was identified for Units 1,2, and 3 pertaining to the
Mplementation of the systematic approach to training for technical training
p igrams We found the overallimplementation of these programs to be generally
inadequate to ensure continued qualification of technical and non licensed personnel
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to perform in plant work. Specifically, the licensee f ailed to properly evaluate .
trainee mastery of tasks and conduct training program effectiveness evaluations.
(U3.M4.1)
Engineering
- At Unit 1, the initialinspection of the A and B reactor water cleanup system filter
cubicles f ailed to identify discrepancies with pipe supports in the areas. The
licensee's initiative to access and inspect normally inaccessible areas is an important
mechanism to monitor the material condition of the plant. However, clear
expectations need to be developed concerning who conducts these inspections and
how the inspections are to be performed and documented. This issue is unresolved
pending NRC review of the corrective actions and completion of the preventative
maintenance program development for normally inaccessible areas. (U1.E1.1)
e The testing of the Unit 1 emergency diesel generator (EDG) was well controlled with
an appropriate level of station management involvement. As issues arose they were
assessed and handhd in accordance with station procedures and policies. At the
end of the inspection period, the EDG testing was continuing. With respect to the
preparation and procedure development, plant management's intervention early in
the process resulted in improvements in the overall restoration process for the
diesel. (U1.E1.2)
e Unit 1 has approximately 38,000 components currently in the production
maintenance management system (PMMS) database. As part of the NU
Performance Enhancement Program (PEP) in the early 1990's, a contractor to NU
reviewed these components and through the material, equipment, and parts lists
(MEPL) program downgraded about 1450 from safety related (SR) to non safety-
related (NSR) in late 1994. It was later determined that this downgrade process had
not been properly performed. Thus about 350 of the downgraded components were
reverted back to SR on an emergency MEPL evaluation. Unit 1 currently has plans
to redo all the system level MEPLs before plant startup, but due to lack of resources
has not begun this effort yet. As outage work is ongoing in Unit 1, individual
component and part MEPL evaluations are being performed as necessary to support
the work and issuance of parts. (U1.E3.1)
- Since 1993 at Unit 2, numerous licensee events reports, adverse condition reports,
and NRC enforcement actions have discussed concerns whether air operated valve
actuator springs are adjusted to apply sufficient force for the valve to perform its
intended safety function. Escalated Enforcement item (EEI) 50 336/96 20125 was
created to address inadequate licensee corrective action regarding the issue. NRC
review of the eel revealed that licensee corrective actions continue to be inadequate
in that the scope of the review was limited to containment isolation valves rather
than all safety related air operated valves. This eel remains open. (U2.E8.1)
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- At Unit 2, the licensee has satisfactorily resolved the potential for leakage of the fire
protection piping joints in the vital switchgear rooms during a seismic event by
replacing the Vitaulic couplings on the piping with welded flanges. (U2 E8.4)
- Review of the MEPL program implementation at Unit 2 indicated that two unit-
specific items require followup inspectiom (1)In 1994,998 components were
downgraded from safety related (Category 1) to non safety related. After a number
of these downgrades were found to be inappropriate,in 1995 and 1990 all of the
downgt,aded components were upgraded back to safety related. The licensee
reviewed the work performed while the components were downgraded and found 7
examples where non safety related parts were installed. The licensee is currently
dispositioning these items; and (2) The licensee is also in the process of evaluating
whether parts classified as ' Undetermined' and non safety related which have no
MEPL have been inappropriately installed. (U2.E8.5)
- The licensee's basis for determining that the Unit 2 main steam check valves are
non safety related was found to be acceptable. However, concerns regarding
recurrent inservice testing f ailures of these check valves is considered unresolved.
(U2.E8.6)
- Four issues were identified during a review of the Millstone MEPL program. These
items pertained to 1) potential for non safety related parts to be installed in safety
related components,2) potential f ailure to assess the impact of downgrading a
component in the quality assurance program,3) potential not to considor normal
operations and abnormal operational occurrences as part of safety related
classifications, and 4) an incomplete PMMS database. (U3.E3.1)
- Unit 3 has approximately 60,000 components in the PMMS database, of which
about 19,000 are safety-related and 3,000 are augmented quality. During PEP
reviews a number of components were originally identified for downgrade, however
this action was stopped in Unit 3 beforo being implemented as a result of lessons
learned on Units 1 and 2. In 1996, Unit 3 began MEPL bill of material evaluations
for all safety related components that have ever had any work performed on them.
As part of this effort, whenever non safety related or undetermined parts are
reclassified to safety related, a full work history is performed to ensure acceptable
quality of parts in these components. Five additionalissues were identified during a
review of specific MEPL components and the CVCS system. (U3.E3.3 and E3.4)
- The inspector reviewed a Unit 3 adverse condition report that addresses the RHR
heat exchanger bolting susceptible to boric acid attack and the actions taken by the
licensee to remove an unsecured structural member installed above safety related
components and to prevent future !nstallations of this nature. The inspector
concluded that the licensee's corrective and preventive actions were adequate.
(U3.E8.1 and E8.2)
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e An apparent violation was identified for Unit 3 pertaining to recirculation spray .
l system design errors which resulted in operation outside the design basis and
system inoperability. (U3.E8.4)
Plant Support
- The licensee has created a framework at Units 1 and 2 to implement an effective
ALARA program. The lack of an effective work control and planning process.
together with the absence of a unit ALARA committee still exists at Unit 3.
(IV.R12)
e Unit 1 management sponsored plant " supervisors walk arounds" in order to raise the
health physics awareness of supervisors observing day to day work activities in the '
field. The walk around tour was extremely informstive arid provided good insights
into radiological waste reduction. The initiative was well roceived by the Unit 1
supervisors and will be expanded to included additional areas such as Security and
Nuclear Oversight. (IV.R5.1)
e Significant improvement was found regarding oversight and organization of the fire
protection program. Although planned corrective actions were found to be
comprehensive, further NRC review is necessary to verify implementation. (IV.F1.1)
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e The fire brigade functioned effectively during the observed fire drill and was well
prepared to combat fires. Significant improvements were demonstrated by the
Training and Site Fire Protection departments, including robust command and
control, teamwork, support provided by Operations, and a good drill critique.
(IV.F4.1)
e An improvement in the quality of assessment provided for the fire protection
program was noted. (IV.F7.1)
e Overall, performance of the Site Emergency Response Organization (SERO) was
good. Simulated events were accurately diagnosed, proper mitigation actions were
performed, emergency declarations were timely and accurate, and offsite agencies
were notified promptly. Protective action recommendations to the State of
Connecticut were correct and timely. Additionally, the information presented during
the management meeting was informative and indicates that the corrective
measures being taken are appropriate. No exercise weaknesses, safety concerns, or
violations of NRC requirements were observed. (IV.P4.1)
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Report Details
Summarv of Unit i Status
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Unit 1 remained in an extended outage for the duration of the inspection period. The
licensee continues to implement configuration management program (CMP) activities,
j engineering reviews, and docketed correspondence assessments to verify compilance with
- the established design and licensing basis of the unit. The successful completion of these
activities is required by NRC order prior to restart of the unit While there is a reduction of
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restart activities at Unit 1, through the end of this year, configuration management program
activitled continue. Following a major reduction.of the contractor work force for the CMP
project, approximately 35 plant personnel from operations, engineering, and maintenance
- were temporarily assigned work on the CMP,
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U1.1.Onorations l
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- U101 Conduct of Operations l
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01.1 General Comments (71707)
i Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
i plant operations During this period the inspectors reviewed activities associated with the . ,
! restoration of the service water system and the emergency diesel generator, both of which
i were being restored following an extended outage for maintenance and plant modification
- work. There was a significant effort on the part of the Unit 1 staff to return these systems
- safety and efficiently to an available status for shutdown risk considerations. This effort is
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discussed in detailin Sections U1.01.3 and U1.E1.2 below.
! 01.2 Ooerations Denartment Command and Control
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a. insoection Scoce (717071
l The position of assistant operations manager was eliminated following the implementation
- of the recovery organization at Unit 1 in October 1996. Subsequently, the recovery team
re instituted the position and required that the shif t managers report directly to the
- . assistant operations manager. Currently, the operations manager holds a Unit 1 senior
i reactor operator (SRO) license, fulfilling the requirement of Technical Specification (TS)
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6.3.1.a., Facility Staff Qualifications. The inspector observed unit operations and
j conducted interviews with a number of shift managers in order to determine if there were
- clear expectations for command and control within the department. This was particularly
Important since the shift managers report to the assistant operations manager and the
! operations manager holds the TS required SRO license.
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b. Observations and Findinos
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On June 26,1997, ths inspector informed the Director, Unit Operations that there
l appeared to be a problem with command and control within the Unit 1 operations
department. This was based on observing unit operations and interviews with a number of
shif t managers, who expressed a concern with the day to day direction for departmental ;
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operation. There was confusion around the operations manager fulfilling the TS SRO
license requirement, and the role of the assistant operations manager they were now
required to report to. This was a new reporting requirement, and a change from the
previous responsibility of the assistant, which was more of an administrative position.
The Director, Unit Operations was unaware of the concerns of the shift managers. By the
end of June, the operations manager, at the request of the Director, interviewed each of
the shif t managers and confirmed that there was a problem in the operation department
with respect to command and control. The operations manager determined that some shif t
managers expressed a concern about the operations manager not being included in the
decision making process and policy making for the department. Some shift managers
complained of receiving contradicting direction in the simulator and during classroom
training, from the operations manager and the assistant operations manager Shift
managers were not clear on management's expectations, how they were communicated,
and the implications if they were not met.
in response to this concern, the operations department performed a "new reporting
relationship review," and discussed all of the issues and concerns identified by the
inspector and the operations manager, The Director, Unit Operation, operations manager,
assistant operations manager, and the five on shift shift managers were present for this
review. A plan was developed following the discussions, which included: 1) revising
Operations Manual,1 OM.3.1, to clearly define the role of assistant operations manger: 2)
solicit feedback from shif t managers routinely to determine if issues are being effectively
addressed; and 3) continue improving cornmunications to assure alignment within the
department.
The inspector conducted follow up interviews with the shift managers and received positive
comments about the new reporting relationship review," and the resolution of the issues.
The operations staff was responsive to the inspector's concems, performed their own
review, and arrived at an adequate solution to the problems. A condition report (CR M1-
971770) was initiated to document the concems and track the corrective actions,
c. Conclusion
Recent changes within the operations department required the shift managers to report to
the assistant operations manager, a new reporting requirement and a change from the
previous responsibility of the assistant, which was more of an administrative position.
Following concerns raised by the inspector, operations management has taken steps to
ensure that the roles of the operations manager and the assistant operation manager are
clearly defined, including the new reporting structure.
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01.3 Service Water Sv11em Restoration
a. inanection Scone (71707)
The inspector reviewed the restoration process for the service water system following an
extended maintenance outage. The restoration included the completion of special
procedure, SPROC 95126, ' Service Water System Outage (IPTE).* The special procedure
was required to establish plant conditions to support the maintenance of the service water
system piping to the reactor building closed cooling water heat exchangers and the turbine
building service water piping.
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b. Observation and Findings
During a review of the restoration process for the service water system, the inspector
determined that the operations staff was not using a new operation departmental
instruction,1 OPS 6.32 " Millstone Unit 1 System Readiness Review," which would have
enhanced the restoration process. This instruction was developed to define the process for
assessing and doeurnenting the restoration of a system and provide guidance on
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documenting and resolving discrepancies identified during the system walkdown process.
The instruction was developed in response to earlier NRC concerns with the lack of a
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methodology the returning aystems to service. The instruction provided a formal process
for returning a system to an operable or available status.
Operations management had formed a team to oversee the operations' portion of the
service water system restoration. Lacking guidance on how to accomplish this task, the
team choose to use the * equipment return to service" departmentalinstruction, which was
a two page instruction applicable to returning a piece of equipment to operable status.
Further inspection identified that a service water restoration plan had been developed,
which identified responsibilities for a project sponsor and departmentalleads from
operations, engineering, maintenance, and planning. The project sponsor was given the
responsibility of providing management oversight of the system restoration activities.
Discussions with the project sponsor, a maintenance manager, indicated that this person
was not aware of his overall responsibility as defined in the plan, but rather considered
himself a management support lead. He considered his responcibility to be the completion
of the physical work and turn over of the system to operations. While a restoration plan
was developed, it doesn't appear that it was implemented. A CR (M1971686) was -
initiated to document the lack of clearly defined roles and responsibilities, and the lack of
an identified point of contact to coordinate all the required activities to restore the system.
A meeting was held between operations and engineering department management to
assign responsibility for performing the specific steps within 1 OPS 6.32 Additionally, a
self assessment was conducted following the service water restoration to identify several
areas for improvement. The individuals involved in the upcoming emergency diesel
- generator (EDG) recovery activities were also present during the self-assessment meeting,
to gain some insight into the planned EDG recovery work. The self assessment
recommendations were documented in a CR (M1971723).
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The inspector observed the service water system recovery activities from the control room.
Pre start briefings were well coordinated and assignments and responsibilities were
discussed with the plant staff. A half hour into the evolution, the shif t manager identified
that the management test lead (MTL) was not on site, when he tried to contact the MTL
with a question concerning the system restoration. The shift manager suspended the
evolution until the MTL was on site. The restoration activities were controlled under
administrative procedure ACP OA 2,27, ' Infrequently Performed Test or Evolution (IPTE)."
While ACP OA 2,27 states that the MTL la responsible for continuous responsibility
(whether on sito or off site) for IPTE oversight, the shif t manager deterrnined that it was
appropriate for the MTL to be on site for the dynamic portion of the evolution.
Additionally, during this time nuclear oversight questioned the adequacy of termination
criteria in the restoration procedure. This issue was evaluated and SP 023.13A " Service
Water Pump Performance Test" was added to ensure that the service water system was
performing its intended function, once it was placed back in service. This later caused a
problem since test conditions specified in the performance test could not be met because
the test was normally performed during normal operating conditions. The restoration
activities resumed the following day.
Operations management assigned a reactor operator (RO) to control and monitor the
activities from the control room. The RO did an excellent job coordinating the step by step
activ!tles with the field operators via the radio, and keeping the unit supervisor Informed of
each step of the restoration. There was also good coordination between operations, the
test engineer, and the MTL, The evolution was also observed by the assistant operations
manager and nuclear oversight. Following the completion of the evolution the termination
criteria was again revised to remove the service water pump performance test and in its
place service water operating parameters such as pump amperes, vibration, and discharge
pressure were added to ensure that the system was operating properly. The inspector
noted that the service water system normal operating procedures did not contain
appropriate guidance for determining normal system operating parameters. This issue was
identified during the development of the termination criteria stated above. A CR (M197-
1713) was initiated to document this concern.
c. Conclusion
During a review of the restoration process for the service water system, the operations
staff was not initially using a new operation departmentalinstruction,1 OPS 6.32
" Millstone Unit 1 System Readiness Review," which would have enhanced the restoration
by providing a formal process for returning a system to an operable or available status.
Additionally, an individual assigned as the overall management lead for the evolution did
not function in that capacity. The reactor operator assigned to control and monitor the
activities from the control room did an excellent job coordinating the step-by step activities
with the field operators, and kept the unit supervisor informed of each step of the
restoration. There was also good coordination between operations, the test engineer, and
the management test lead. The inspector noted that the service water normal operating
procedures did not contain appropriate guidance for determining normal system operating
parameters following the system restoration.
- _ -- - - .- . . - - - . -
_ _ _ _ _ _ . _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _
.
.
.
5
U1.11 Mainianant
U1 M3 Maintenance Procedures and Documentation
M 3.1 Standbv Llould Control Tank
a. Insoection Scone _(02707)
The inspector reviewed the preparation and planning activities associated with the retrieval
of a hatch bolt from the standby liquid control (SDLC) tank. While sampling the SBLC tank
on June 19,1997, the threaded rod that holds the tank cover in place unscrewed and
dropped into the tank (CR M1971520).
!
b. Observations and Findinas
Unit 1 nuclear oversight (performance evaluation (PE) group) became aware of the plans to
retrieve a hatch bolt from the SBLC tank at the 6:30 morning work control meeting, on
June 24,1997. Af ter some discussion with the chemistry supervisor, it was apparent that j
the work was going to be performed under an automated work request (AWO),in a day or I
two, with no pre job briefing up to that point, no system engineering involvement, and no
nuclear oversight involvement. PE suggested that a meeting be set up to bring all
interested parties together and discuss the evolution. A number of questions were raised
by PE at that meeting concerning the use of an AWO in place of a special procedure,
foreign material exclusion (FME) control, material compatibility, and possible chemical
interactions between the contents of the SBLC tank and all equipment being used for
retrieving the hatch bolt.
Subsequent to the initial meeting, the inspector noted significant resistance from the line
personnel to PE concerns about using an AWO to perform the work. PE's concerns
included the f act that this was an infrequently performed activity. DC 1, * Administration
of Procedures and Forms," states that special procedures are prepared as necessary to
support infrequently performed activities which are not to be included in the permanent list
of station procedures. There were discussions about whether or not this activity was
infrequently performed, e.g., removing something from a tank. PE was concerned that
since this was a category 1, safety system, and the tank contained heater coils and air
spargers, special precautions were needed to address these issues, which would require
involvement by system engineering. The line personnelinsisted on using an AWO and PE
provided a large number of comments following a review of the draft AWO At that time,
the line planned to perform the work using a revised AWO, which inchaded PE's comments.
After continued dialogue between the line personnel and nuclear oversight that lasted
approximately two weeks, the decision was made to open the tank and determine the
exact scope of the recovery activities. The inspector observed the activity, which was
appropriately controlled, FME controls were in place. Following that activity, plant
management determined that a special procedure would be written, and work would be
performed in August 1997.
_ _ . _ _. . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _
c
.
6 , ,
c. Conclualon l
The inspector reviewed the preparation and planning activities associated with the retrieval
of a hatch bolt from the standby liquid control (SBLC) tank. Nuclear oversight
(performance evaluation (PE) group) became aware of the plans to retrieve a hatch bolt
from the SBLC tank and raised a number of questions concerning the use of an automated
work order in place of a special procedure. The lack of clear guidance on when a special '
procedure is sequired resulted in significant resistance from the line personnel to PE
concems about using a woik order to perform the work. The decision was made by plant
management to develop a special procedure for the bolt retrieval. *
U1 M8 Miscellaneous Maintenance issues
M8.1 (Closed) Unresolved item (URll 50 245/94 014 13; Qualitv Control involvement in
i
Safetv related Work Actlylijst (SIL 108 UPDATE)
a. insoection Scone 162707)
-
-
The inspectors reviewed the licensee's findings and corrective actions associated with the
,
.
determination of quality controlinvolvement in safety related work activities and for
l
determining when inspection hold points were required,
b. Dhagrvations and Findinas ,
i. The unresolved item concerned maintenance on EDG air start system solenoid-operated
valves (SOV). The maintenance was a rebuild activity and the inspector found that the
work was performed without a PORC approved procedure, and there was a violation issued
for that finding. In addition, the procedure in place at the time, ACP OA 2.02C, Work
Control, provided guidelines for determining quality controlinvolvement in safety related ,
work activities and for determining whether inspection hold points were required...The
planner's conclusion that no quality services department involvement was required for the
SOV maintenance appeared to have been consistant with those guidelines. At the time of i
the inspection, the inspector was concemed with the adequacy of those procedural
guidelines. Nuclear oversight needed to reevaluate the policies and guidelines set forth in f
ACP OA 2.02C A URI was initiated to document this concern,
The reevaluation was completed and the licensee implemented a new procedure, WP 8003,
" Unit 1 Work Package Planning," which included a step that provided definitive guidance -
on when work orders required a quality assurance (OA) review. The guidance was.-
= changed from listing six activities that need QA involvement, which is open to
interpretation, to a " management by exception" concept, listing the 23 activities that do
not require OA' involvement, with all others requiring a OA review. - Additionally, as part of
the recovery plan for nuclear oversight, two procedures were developed that gave nuclear
l . oversight ownership of the hold point program and responsibility for assigning hold points _
on all AW0s. A OC tech support group was established to provide this function, with all
l AW0s being reviewed by this group prior to implementation.
1
,
4
e- -N, , ,w----e" - - - - - ym~~ --
,, ,,s-w-s,-,r.e--s-,,,n,-e,e,e-v.wweem-m-
-
w----,-w -,-,N--~ .-w,r&~e,-,,w,-- , rw - - .-ms- vn,-y m, sm e m -r -'
-
._ _ _ _ _
, __ . _ . . _ _
.
'
7
c. Conclusions
. The NRC concluded that the licensee's corrective actions would address the adequacy of
procedural guidelines for determining quality control involvement in safety related work
activities. This item is closed. As feedback to the package development process, the
inspector concluded that the open item package had most of the requisite information,
however, the inspector needed to consult the preparer of the package to understand how
the information addreseed the issue. ,
.
Q1.lli Enoineering
U1 E1 Conduct of Engineering
E 1.1 A and B Reactor Water Cleanuo Svstem Filter Cubicles
a. Insoection Scone (375511
The inspector rev owed a video tape record of an inspection that was conducted in the A
and B reactor '.<ater cleanup (RWCU) system filter cubicles. On June 1617,1997, the A
and B RWCU filter entrance floor plugs were removed for an inspection of the areas. The
inspection was part of the licensee's program for entering normally inaccessible areas,
b Observations and Findings
The work activity was performed under an AWO with a system engineering sign off for the
completed inspections. A video tape record of the inspection was completed and the
inspector requested a copy for review. While reviewing the tape, the inspector noted an
object wedged between two pipes in a pipe sleeve in the 8 filter cubicle. The system
engineer was contacted and the inspector was informed that the discrepancy had not been
identified or documented in a condition report. Tt e inspector also reviewed the completed
AWO that stated that two pieces of wood and one pen were removed from the floor of the
'B' cubicle; no additional discrepancies were noted. The system manager, his supervisor,
and the inspector reviewed the video tape and identified some additional discrepancies of
the same type, wedges in pipe sleeves. A CR (M1971678) was initiated as a result of
that review to document the discrepancies and corrective actions, and an assignment was
added to the CR to determine why the initial inspection failed to identify the discrepancies. .
Discussions with the system manager rerponsiblo for developing a strategy for the
inspection of normally inaccessible areas, indicated that a prever.tive maintenance program
was being established to ensure that these areas are inspected on regular basis. All but
one of the sixteen areas designated as normally inaccessible at Unit 1, are inside structures
considered within the NRC Maintenance Rule 10 CFR 50.65, in-scope population.
Therefore, these areasi are subject to a structuralinspection to be conducted every two
refueling cycles to ensure compliance with the structural monitoring provisions of the
maintenance rule.
.
. .
.
4
8
'
c. Conclusions
The inspector concluded that the licensee's initiative to access and inspect normally
inaccessible areas is an important mechanism to monitor the material condition of the
plant. However, clear expectations need to be developed concerning who conducts these
inspections and how these inspections are to be performed and documented. This issue is
unresolved (URI 245/97 202 01) pending NRC review of the CR corrective actions and
completion of the PM program development.
E1.2 Emeroencv Diesel Generator Testina
e, insoection Scone (375B1)
The inspector reviewed the restoration process for the emergency diesel generator (EDG)
following maintenance and modification work.
i
b. Observations and Findinas
During a PORC meeting conducted on June 4,1997, four different special procedures were
proposed for the restoration of the EDG following maintenance and modification work. At
that point, plant management determined that the staff would need to perform a review of
all the EDG post maintenance testing, to identify any overlapping testing that was required
for the EDG restoration. This was needed to prevent duplication of the testing and provide
an efficient methodology to complete the required testing. A special procedure was
created following the review under administrative procedure ACP-Q'A 2,27, " Infrequently
Performed Test or Evolution (IPTE)," to encompass all the work required for restraation.
,_ The special procedure consisted of six phases including monitoring, testing, and data
gathering steps. The test included post maintenance and modification testing and limited
the number of EDG test starts by performing the testing in a logical, efficient manner.
The inspector observed the initial briefing for the test conducted on July 15,1997, by the
management test lead (MTL) and the test engineer, and found that it was comprehensive
and provided an good overview of the IPTE. The termination criteria and responsibilities for
plant personnel were explicitly stated. A number of issues that were raised at the briefing
and were reviewed and appropriately added to the procedure. For example, the reactor-
operator (RO) suggested adding a step to line up the in service systems to the S1 power
supply prior to the start of the test. This had been discussed during the briefing, but the
RO noted that it was not part of prerequisite steps in the IPTE.
The inspector noted that the lessons learned from the earlier service water restoration were
included in this evolution, including identifying a management lead individual responsible for
the oversight of the system restoration activities, and the use of 1 OPS 6.32 " Millstone
Unit 1 System Readiness Review."
_ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. _ _ _ _ _ . .
.
. .
..
.
-
9
c. Conclusions
The testing of the emergency diesel generator was well controlled with an appropriate level
of station management involvement. As issues arose, they were assessed and handled in
accordance with station procedures and policles. At the end of the inspection period, the
l EDG testing was continuing. With respect to the preparation and procedure development,
the inspector found that management's intervention early in the process resulted in
improvements in the overall restoration process for the diesel.
U1 E3 Engineering Procedures and Documentation
E3,1 Unit 1 MEPL Status Uodate
,
The overall site material, equipment, and parts lists (MEPL) program was reviewed;
comments and discussion that apply to all three units are provided in Section U3 E8.1.
This section provides Unit 1 specific discussions only.
Unit 1 has approximately 38,000 components currently in the production maintenance '
management system (PMMS) database. As part of the NU Performance Enhancement
Program (PEP) in the early 1990's, a contractor to NU reviewed these components and
I
through the MEPL pro 0 ram downgraded about 1450 from safety related (SR) to nc,n safety-
f related (NSR)in late 1994, it was later determined that this downgrade process had not
been properly performod. Thus about 350 of the downgraded components were reverted
back to SR on an emergency MEPL evaluation. The other 1100 were each given a full
MEPL evaluation with the following results. About 20% were converted back to SR and
the remaining 80% were determined to be appropriately downgrsded to NSR.
Unit 1 currently has plans to redo all the system level MEPLs before plant startup, but due
to lack of resources has not begun this effort yet. As outage work is ongoing in Unit 1,
'
individual component and part MEPL evaluations are being performed as necessary to
support the work and issuance of parts. Unit 1 has not decided on the level of MEPL
evaluations to be performed for component Bill of Materials (BOM) Currently, full BOMs
are not being completed even for components that are being worked on AWOs. Unit 1 is
performing full historical reviews of work history for components ur parts that are upgraded
from NSR to SR but not for items upgraded from Undetermined (U) to NSR.
-
,
.
Reoort Detalla -
Summarv of Unit 2 Stalus
Unit 2 entered the inspection period with the core off loaded. The unit was initially shut
down on February 20,1990, to address containment sump screen concerns and has
remained shut down to address an NRC Demand for Information (10 CFR 50.54(f)) letter
requiring an assertion by the licensee that future operations are con' ducted in accordance
with the regulations, the license, and the Final Safety Analysis Report.
U2.1 Ooerations
U201 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
plant operations, in general, the conduct of operations was professional and safety-
conscious. Operator performance was good in evaluating shutdown risk by maintaining
awareness of plant conditions and equipment availability. In particular, on July 14,1997,
operators exhibited a good questioning attitude regarding the planned removal from service
of the spent fuel pool area ventilation supply fan, F 20. Operators noted that procedure OP
2264, " Conduct of Outages," was unclear whether the shutdown risk " Key Safety
I
Function *' for spent fuel pool area ventilation boundary would remain " Green" with f an F 20
removed from service. A condition report was generated to address the concern,and
procedure OP 2264 was changed before proceeding with planned maintenance activities on
f an F 20. Other noteworthy observations are detailed in the sections below.
01.2 Removal of Non-conservative Technical Soecification Clarifications from the
Technical Reauirements Manual
a. Insanction Scone (71707)
The inspector evaluated the licensee's efforts to remove non conservative technical
specification (TS) clarifications from the technical requirements manual (TRM).
b. Observations and Findings
T% licensee performed an evaluation the 27 technical specification clarifications and
ca.egorized 7 of them as more conservative,10 as less conservative, and 10 of them being
neutral as compared to the corresponding technical specification. On July 15,1997, the
licensee completed their effort of removing from the TRM all 10 technical specification
clarifications that were categorized as less conservative. The inspector verified that each of
the non conservative TS clarifications that could be considered a TS non compliance was
appropriately reported to the NRC in accordance with 10 CFR 50.73,
c. ConcluslQD
The licensee initiated offort in removing 10 non conservative technical specification
clarifications from the TRM was good.
.
_ - _ _ _ _ _ _ _
.-
11
l4
01.3 Timeliness of Corrective Ac' ans Condition Reoort Backlog
a. lasagstion Scoce (717'
The NRC evaluated the timelint s in which the licensee completed corrective actions
i associated with Unit 2 conditior sports (CRs).
I b. Observations and Findinos
'
l Timeliness for completion of corrective actions has been a longstanding concern at
Millstone. Having a CR backlog in itself is not a reflection of poor performance because as
the threshold for writing CRs decreases, the CR backlog willincrease accordingly. The
concern is the number of CRs that are not closed in a timely manner. To help provide the
NRC some sense of the licensee's progress in addressing the timeliness concern, the
licensee was asked to provide the number of CRs having outstanding corrective actions
that are greater than 120 days old. Although the NRC does not consider 120 days a level
of excellence nor is it acceptable when addressing immediate safety concerns,it does
provide some understanding of licensee management effectiveness in addressing the
corrective action timeliness issue.
At the end of the current inspection period, there were 780 CRs greater than 120 days old
that have not been closed which is a decrease from 828 CRs at the end of the last
I
inspection period. Out of the 780 CRs currently greater than 120 days old,200 of them
were initiated in 1997,
DEPARTMENT CRs OLDER THAN 1997 CRs OLDER
120 DAYS THAN 120 DAYS
Operations 48 10
Design Engineering 255 62
Technical Support 182 26
Work Planning 25 8
Maintenance 54 26
l&C 28 7
Safety / Licensing 47 8
Other 141 53
TOTAL 780 200
12 ,
c. Conclusions
The total backlog of 780 CRs that are greater than 120 days old indicates that timeliness
for completing corrective actions continues to be a concern. The backlog of 1997 CRs
greater than 120 days old is of greater concern because it reflects the performance of the
new management organization. The new management planned to demonstrate a higher
standard by dispositioning newly generated CRs in a timely manner while establishing a
plan for worising off the CR backlog that existed when they arrived. However, the backlog
of 200 CRs greater than 120 days old that were generated in 1997 indicates that the new
management is also ineffective in addressing the corrective action timeliness issue which is
considered a significant weakness. As discussed in NRC Inspection Report 50 330/96-04,
timeliness and effectiveness of corrective actions is an area in which the licensee must
demonstrate sustained improved performance.
U2 03 Operations Procedures and Documentation
03.1 Reactor Buildina closed Coolino Water Suroo Tank Minimumhynj
a. IDioection Scoco (71707)
.
The inspector evaluated the licensee's administrative controls for maintaining the reactor
building closed cooling water (RBCCW) system surge tank level.
b. Observations and Findinas
The RBCCW surge tank, which is utilized by both facilities (trains), is normally maintained
at 50 percent level by an automatic makeup valve in the primary makeup water system.
The RBCCW surge tank has an internal vertical weir that rises to the 37 percent level
which allows draining of one f acility while maintaining the other f acility in service. To
support maintenance on RBCCW system components, the licensee had drained facility 1
and was maintaining level on the f acility 2 side of the RBCCW surge tank was than 32
percent. Operators were periodically opening the primary makeup water supply to f acility 2
to account for minor system leakage. However, the inspector found that the required
RBCCW surge tank level band was not proceduralized nor was it specified on the Shif t
Turnover Report. One control room operator stated that operators had been filling the
RBCCW surge tank when level reached approximately 20 percent. The inspector was
concemed that with an undefined minimum surge tank level, RBCCW system operability
could be affected due to potential net positive suction head (NPSH) concerns for the
HBCCW pumps.
The inspector discussed this concern with operations management and as an interim
measure, the licensee added a surge tank level band of 24 percent to 32 percent to the
Shif t Turnover Report. Subsequent review by plant engineering indicated that as long as
there is a visible levelin the surge tank, there would be sufficient NPSH for the RBCCW
pumps. Nevertheless, the licensee agrees that the RBCCW level band should be
proceduralized and is in the process of evaluating the necessary procedure changes.
. .. .- . - . . .- -.
l
'
l
13
c. Conclusion
Although the licensee determined that there would be sufficient NPSH available to the
RBCCW pumps, the failure to evaluate and proceduralize the level band that operators
should control RBCCW surge tank level was considered a weakness.
U2.Il Ma]nttnante
U2 M8 Miscellaneous Maintenance issues
M8.1 (Closed) Insoector Follaw uo item 50 336/95 201 03: Procedure Level of Use
Desionation (SIL 8 Individual item Closed)
e, ingstion Scong.192902)
The scope of this inspection included a review of Inspector Followup Item (IFI) 50 336/95-
201 03.
b. Observations and Findinas
This item concerned the fact that most maintenance and surveillance procedures were
classified as " General Use" versus * Continuous Use." The procedure Level of Use
designations are defined in procedure DC 4, " Procedural Complience," as follows:
Continuous Level of Use Procedure
- A procedure that controls a work activity that is critical, complex, or involves
infrequently performed evolutions or activities.
- Requires step-by step use to prevent immediate effects on nuclear or
personnel safety and plant reliability.
General Level of Use Procedure
- A procedure that involves evolutions or work activities on plant equipment or
has multiple actions required to perform a task or tasks.
- Procedure must be referred to as necessary during the performance of the
work activity to erwure the evolution is performed correctly.
- The level of detail u. .vs the user to read an entire sequence and perform it
before referring to the procedure again to confirm the complete task and
prepare for the next task or sequence.
Information Level of Use
- A procedure that involves administrative or technical evolutions or processes.
- Procedure requires periodic review for familiarity but is not required in the
field.
The inspector found that only five mechanical and electrical procedures had been changed
from " General Use" to " Continuous Use" during the past two years which reflects licensee
management's view that the " General Use" category is adequate for most procedures.
14
'
Procedure DC 4 specifies that the Level of Use Indicates the minimum required degree of
reference to the procedure during portions of the work activity and does not alter
expectations for procedure adherence,
c. Conclusion
The NRC considers IFl 50 336/95 20103 to be closed based on: (1) There is no specific
regulatory requirement that defines or mandates procedure Level of Use classification: (2)
Although there have been examples of procedural adherence issues documented in NRC
inspection reports since this IFl was opened, there were no documented examples of where
the procedural noncompliance could be attributed to the Level of Uso designation; and (3)
inspector observations indicate that surveillance procedures are generally referred to on a
step by step basis even though most surveillances are " General Use." Even though this
item is being closed, the NRC considers procedure Level of Use to be an area where
management standards and expectations should be promulgated, particularly with
surveillance procedures to ensure understanding by the licensee's staff.
M8.2 (Closed) Licensee Event Reoort 50 336/97 04: Hlah Pressure Safetv inlection (HPSI)
Pumo Allonment
a. Insoection Scone (92902)
The inspectors reviewed the corrective actions taken by the licensee to prevent recurrence
of the event described in the subject LER.
b. Observations and Findinos
On January 23,1997, th, scensee discovered that three HPSI pumps were aligned such
that they were all capable of injecting water into the reactor coolant system. The plant
was in the refueling mode (Mode 6) with the reactor vessel head removed. In that mode
plant technical specifications only permit two charging pumps and two HPSI pumps to be
,
capable of injecting into the reactor coolant system (RCS) to prevent an inadvertent RCS
overpressurization. The three HPSI pumps were inadvertently aligned, due to personnel -
error, for approximately 36 minutes during preparations for surveillance testing. The -
condition was immediately corrected upon discovery. .
Additional corrective actions included the revision of all affected surveillance test
procedures to include pump alignment requirements. A detailed briefing of the event and
causal factors was given the operating shift crews. The inspector reviewed the revised
test procedures and the briefing provided to the operators,
c, Conclusions
The licensee's corrective actions associated with this LER were determined to be
acceptable. The safety significance of this event was minimal because: 1) With the reactor
__ vessel head removed, the inadvertent injection by three pumps could not overpressurize the
reactor coolant system; and 2) If operators had not discovered the HPSI pump alignment
,
._.-1.- - ..,._..._...=._--,mm__.-_ _ _ , , - - , _ m - , , , . .. ...-,_-<-,.-m ,_w__. --
- - . _
__-_ _ __ . .
._ .
.
16
during the shif t, the condition would have been identified during the shif tly performance of
the control room operator logs per procedure OPS Form 2614A 2, * Control Room Daily
Surveillance, Mode 6 and Defueled.* This licensee identified technical specification non-
compliance is being treated as a Non Cited Violation, consistent with section Vll.B.1 of the
NRC Enforcement Poliev. This LER is closed.
l
U2.lli En91ntidng ;
U2 E8 Miscellaneous Engineering Issues
,
E8.1 LClosed) IFl 50 336/93 20-05 & LER 50 336/9711-and (Undatel eel 50 336/96-
20125: Testina of Dual Function Valves (Update Significant item List No. 30)
a. insoection Scone (92903)
The inspector reviewed the corrective actions taken by the licensee to address questions
regarding testing of dual function air operated valves. The licensee defines dual function
, valves as those valves that have an isolation function at containment design pressure and
at the normal system operating pressure.
b. Observations and Findinos
As discussed in Licensee Event Report 60-336/93 23,in June 1993, the licensee
experienced problems with leakage past the letdown isolation valves 2 CH 089 and 2 CH-
615 while attempting to establish isolation to support repairs to a manual stop valve in the
line. The plant was at normal operating pressure (2250 psig) at that time. The cause of
the leakage was found to be improper adjustment of the spring preload on the air operators
during prior maintenance. The LER documented the immediate corrective actions taken
which included the adjustment of the affected valve operator spring preloads and
verification of the isolation capability at normal reactor coolant system pressure. The LER
also noted that a maintenance procedure had been developed for the actuator type used on
the af fected valves. This procedure included detailed spring bench setting requirements.
Procedures for all dual function valves were to be completed prior to the next refueling
outage and retest requirements involving verification of isolation against normal system
pressure for the valves were also to be defined,
in February 1994, a violation was cited for the performance of the work on the air
actuators without written procedures. At that time, the inspector noted that the violation
could have reasonably been prevented by corrective action for a previous licensee finding
concerning valve 2 EB-99. The licensee's violation response specified that procedures for
pneumatic actuators would be completed prior to May 6,1994. Additionally, the licensee
committed to specifying retest requirements to verify valve isolation capability against
normal system pressure for all valves that function in a dual role.
.
e
16
in June 1995, Adverse Condition Report (ACR) 1935 was written to identify that actions
had not yet been taken to implement the commitment to ensure the required isolation af
dual function valves against normal system pressure.
In response to an NRC inspection finding that the licensee's commitment had still not been
completed, in March 1996, ACR 9623 was written to identify the potential that 23 dual
function valves may not be set to isolate against normal system pressure, The licensee
planned to perform as found testing of the valves following the core off load, Escalated
Enforcement item (EEI) 50 336/96 20125 documented an apparent violation for the
licensee f ailure to implement prompt corrective action to resolve the dual function valve
testing concern,
in March 1997, Condition Report (CR) M2 97 0412 was written to document the results of
the as found testing. The testing method involved measuring the pressure needed to
operate the valva and then using the air pressure results to determine the seating force the
valve operator sving was transmitting to the valve disc,
Following the completion of testing and evaluation of test results,in May 1997, LER 50-
336/97 011 reported that 11 of the 23 valves tested were not capable of closing to a leak
tight condition against normal system operating pressure, The corrective actions specified
in the LER were to: (1) revise the appropriate procedures prior to entering Mode 4 to
ensure that the proper valve control parameters are specified and verified af ter
maintenance that could affect dual function valve closing forces; and (2) adjust the
affected valves to ensure they properly close against containment pressure and normal
operating system pressure prior to entering Mode 4. The licensee also stated that these
actions satisfied the commitment to specify the retest requirements for dual function
valves.
The inspector reviewed the licensee actions taken to date to resolve the issue of
inadequate testing of dual function valves, Since the cwse of the original problems was
attributed to the lack of adequate procedures for performing maintenance on valve air
actuators, the inspector questioned why the concern for adequate closing force would not
apply to all air actuators in the plant, not only valves with dual functions. The licensee had
not reviewed other air operated valves, in particular those valves that have safety
functions, to assess the valve operability, The licensee acknowledged this concern and
prepared Memorandum MM2 97 043, dated July 2,1997, which discusses planned actions
to screen, evaluate, and test additional air operated valves to ensure that valves that are
critical to the safe operation of the plant are set up properly,
c, Conclusions
The NRC concluded that the licensee has established adequate methods for testing the air
operated valves to ensure that adequate force is applied by the actuator springs for the
valve to perform its function. However, despite numerous LERs, ACRs and NRC
enforcement actions that have documented the air operated valve concerns since 1993,
licensee corrective actions continue to be inadequate in that the scope of the review was
limited to the * dual function" valves even though other safety related air operated valves
i
!
4
17
'
could have the same setup problems. eel 50 330/96 20125 (and Significant items List
No. 30) remain open pending:
- NRC review of the completed licensee corrective actions committed to in LER 50-
330/97 11;
e NRC review of the licensee findings and corrective actions relative to non dual
function air operated valves; and,
o NRC review of any additionallicensee actions that may result from the resolution of
eel 50 330/96 20125. Because eel 50 330/96 201 25 encompasses the technical
issues and corrective actions discussed in LER 50 330/9711, the NRC will use this
eel to track those issues; LER 50 330/9711 is considered administratively closed.
Inspector Followup item (IFI) 50 330/93 20-05 identificJ e concern that reduced pressure
testing of 10 CFR 50, Appendix J, may not adequately assure the leak tight integrity of
valves that may be required to close at full reactor coolant system pressure. The inspector
noted that the Appendix J testing verifies the valve seating capability at containment
design pressure. This testing, combined with additional testing to ensure adequate closing
force at full system pressure, demonstrates the ability of the valves to function at full
system pressure. Since the actions being taken to implement the additional testing are
being tracked as discussed above,IFl 50 330/93 20-05 is considered closed.
E8.4 [Vodate) Escalated Enforcement item 50-330/96 201 36: Inadeauste Corrective
Action Concernina a Seismic Deslan Deficiencv of a Vital Switchaear Room CantcI
(Closed Significant items List No. 33)
a. Insntetion Scoce (92903)
The inspector reviewed the licensee's modification to the fire protection piping in the cable
spreading area of the turbine building for precluding potentialleakage of the Fire Protection
(FP) class 2 piping over class 1 components and the design basis for precluding the
unwanted seismic class 2 over 1 interaction in this cable spreading area,
b. Observations and Findinas
On September 29,1995, the licensee's Service Water System Operational Performance
(SWSOPI) identified a concern with Vitaulic couplin9s in a 3" fire protection (FP) pipe
located over chiller X 182 in the cable spreading area of the turbine building at elevation
45' 0", The possibility existed that the Vitaulic coupling could have leaked during a
seismic event, thus, actuating the moisture detector in the coffer dam around the X 182
chiller which then would close the service water flow to the coolers.
The inspector reviewed the licensee's records, interviewed the cognizant personnel, and
performed a walkdown to ensure that the corrective action that replaced the Vitaulic
couplings with welded flanges to assure leak tightness of the fire protection system pipe
joints was properly implemented. During the walkdown, the inspector observed that the
_ _
.
18 ,
Vitaulic couplings on the 3" fire protection piping over chiller X 182 located in the cable
spreading area of the turbine building had been replaced with welded flanges es prescribed
by the corrective action. The rest of the FP piping appeared to be well supported to
withstand a postulated seismic event.
During the walkdown, the inspector noted that a segment of thit. FP piping (elbow) has a
1/4" of clearance from a safety related a cable tray, thereby creating a possible
nonconformance with the seismic 2 over 1 Interaction criterion. The licensee initiated a
condition rep' ort to prepare a calculation to evaluate the as found configuration during a
postulated seismic event. The inspector reviewed the licensees' calculation No. 97 ENG-
01819C2, Revision 0, and concluded that the licensee has performed a detall caleMation
with a finite element computer model of ths subject pipe t :Ing a standard computer
program. The analysis was performed using the correct parameters from the design basis.
The results showed that the maximum relative displacement between the FP pipe and the
cable tray in question is 0.078 which is less than 1/4". Therefore, the existing 1/4"
clearance is adequate,
c. Conclusion
. The licensee has satisf actorily resolved the potential for leakage of the fire protection
piping joints during a seismic event by replacing the Vitaulic couplings on the piping with
welded flanges. The proposed violation and potential escalated enforcement action for this
item is still under review by the NRC.
EB.5 luodm) Escalated Enforcement items 50 336/96 201 42 & 43 Material.
Eguinment and Parts List Prooram (Update Significant items List No.18)
a. Jr aoection Scone (92903)
The overall site material, equipment, and parts lists (MEPL) program was reviewed;
comments and discussion that apply to all three Millstone units are provided in Unit 3
Section U3 E8.1. This section provides Unit 2 specific discussions only,
b. Observations and Findinus
!
Unit 2 has approximately 60,000 total components in the plant, of which about 12,000
are safety related. As part of the Performcnce Enhancement Program (PEP)in the early
1990's, the licensee reviewed the quality classification of about 28,000 components, in
late 1994, the MEPL program was utilized to downgrade 998 components from safety-
related (Category 1) to non safety related, it was later determined that a number of these
downgrades were not correct. Thus, in 1995 and 1996 all of the downgraded components
were upgraded back to safety related. During the time period that the components were
'
improperly classified, work was performed on them as non safety related components,
creating the possibility ths,t substandard parts may have been installed. To address this
concern, the licensee reviewed each of the 400 to 500 automated work orders (AWOs)
that had been performed during this time period on these components to determine if non-
safety related replacement parts had been installed. Seven instances were identified that
-
_ _ _ _ _ _ _ _ - - - - - _ - - - _ - _ _ - - _ _
. _ _ _ _ _ _ _ - _ _ _ _ _ - - _ _ _ - _ _ _ _ -
-
. .
. 19 i
required that nonconformance reports (NCRs) to be issued and various corrective actions to
be taken. As of the end of this inspection report period, not all of the NCRs had been fully
dispositioned.
As one action to adda,ss the various concerns associated with classification of
components and the MEPL pre vam, Unit 2 is performing a MEPL re review of all systems
and all safety related components. This is being done at the component level and is
scheduled for completion in the Fall of 1997.
MEPL' evaluations are not only performed at the component level but also the part level
because parts that are not critical for the component to perform its intended safety
function may be classified as non-safety related. For each unit, a number of condition
reports (CRs) have documented that some parts listed on the Bill of Materials (BOMs) for a
safety-related component were either classified as ' Undetermined' or non safety related.
This raises the question of whether non-safety related parts have been inappropriately
installed in safety related components. At Unit 2, licensee corrective actions to address
this concern included: (1) performing BOM MEPLs prior to working on components during
the current mid cycle outage, and (2) performing a full historical review of work orders of
any part or component that has its MEPL classification upgraded from ' Undetermined' or
non safety related to safety related. The inspector asked the licensee why it was
appropriate to limit the historical review to only those parts that have been upgraded
because components that have not been worked during the mid cycle outage, whose BOM
MEPL has not been performed, may have had non safety related parts installed. At the
close of the inspection period, the licensee was still gathering information to justify their
plans,
c. Conclu1}DD
Escalated Enforcement items 50 336/96-201-42 & 43 remain open to allow further NRC
inspection of the nite-specific and programmatic MEPL concerns that are summarized in
in Unit 3 Section U3 E8.1.
E8.6 (Ocen) Unresolved item 50-336/97-202-02) Main Steam Check Valves Deslan
Adeauaev (Closed - Significant items List No. 45)
a. Insoection Scoce (929021
This inspection involved a review of Adverse Condition Report (ACR) M2 96-0542, which
questioned whether the non-safety-related classification of the main steam check valves
was appropriate. The check valves are credited in the accident analysis for preventing the
blowdown cf the intact steam generator in the event of a main steam line break (MSLB)
upstream of the main steam isolation valves (MSIVs).
- . ,
_ _ - _ _ _ _ _ _ _ _ _ __
.
20
.
b. Observations and Findinos
in addressing the ACR, the licensee provided a detailed licensing basis history regarding the
main steam check valves. There is no licensing basis documentation that specifies
explicitly whether the check valves are considered safety related or non safety related.
However, the seismic classification of the check valves that is explicitly stated in the Final
Safety Analysis Report (FSAR) combined with NRC guidance documentation issued after
Millstone 2 was licensed, provides a sufficient basis to conclude that the non-safety-related
classification of the check valves is acceptable. The original FSAR, Section 10.3.2.1,
states that main steam line up to and including the MSIVs are required to be Seismic Class
I and all downstream components (which includes the main steam check valves) are
considered seismic Class ll.
Although the following information is contained in NUREGs that were issued af ter Millstone
7 was licensed, they still provide insights on the staff's position regarding the issue. The
NRC discusses and generically accepts the use of non safety >related main steam check
valves in NUREG-0138, " Staff Discussion of 15 Technicalissues Listed in Attachment to
November 3,1976 Memo from Director, NRR to NRR Staff." NUREG 1038, Issue No.1,
discusses the treatment of non-safety-grade equipment in evaluations of postulated steam
line break accidents. Although the main steam checks valves were not the focus of the
evaluation, NUREG-0138 stated that "for the purposes of this discussion, a safety grade
component is defined as one which is designated as seismic category I.... The remaining
Valves in the rnain steam and main feedwater lines are designated as non-safety grade
components...." The NRC notes that for accidents involving spontaneous f ailures of the
secondary system piping, that are not part of the primary system boundary, less stringent
requirements are imposed on the quality and design of systems needed to cope with the
secondary system ruptures.
Due to their use as a backup to safety-related components in the safety analyses, the
inspector also reviewed the Inservice Testing (IST) and Inservice Inspection (ISI)
requirements associated with the main steam check valves. The IST program requires that
the licensee verify during each cold shutdown that the valve travels smoothly and
completely to the closed position as steam plant load is reduced. The inspector reviewed
the following:
-
IST surveillance test SP 21134, " Main Steam System Valves Operational Readiness
Test," Rev.10, and the Surveillance Cover Sheet ENG. Form 21134, Rev. 4, which
contains the acceptance criteria and which records the data, test acceptability, and
approvals:
- The check valve disassembly and inspection program.
The inspector noted two errors in Rev. 4 of ENG. Form 21134 with respect to the position
of the valves during the test as being fully open or fully closed. The licensee concurred and
initiated a procedure change. The inspector also selected recent tests and noted that there
have been difficulties with the valves passing the test. The maintenance history for the
vcives was also reviewed and the inspector noted a moderate amount of work required to
l
l
.. ...
. . . . - . . . . _ . . . - . - - . . . . - - . . . _ - - . . - . - . . - - . . . - . . . - . - . _ . - - . . - . = - . . -
.,
,
4
4
21
. .
maintain the valves. The inspector reviewed procedure EN 21221, liev. O, " Check Valve
Examination and Testing," which places these check valves in the Priority 3 Group for
examination once every five refueling outages. This procedure was placed in a "Do Not
Use" status as of September,1993,
c. Conclusion
The licensee's basis for determining that the main steam check valves are non-safety-
related was found to be acceptable and Significant items List No. 45 is considered closed.
The area of inspection, maintenance, and testing associated with these check valves is
unresolved and will be further reviewed to ensure that appropriate activities are being
accomplished to ensure reliable functionality of the valves. (Unresolved item 50 336/97-
202 02)
.
.,a , , + =- -
.a,, aas-u a +. . ~ . , - -- .u --.. ~ - a ~-o - --~ -
.
Unit 3 Renort DetaHA .
Summarv of Unit 3 StalMA
Unit 3 remained in cold rhutdown (mode 5) status throughout the. inspection period. The
licensee continued to implement unit recovery activities, while continuing to develop an
Operational Readiness Plan directed toward the objectives and milestones leading to both
the physical readiness of the Unit 3 restart and the preparedness for the NRC operational
readiness inspection conduct.
On July 16,1997 the licensee notified the NRC that the problem identification phase of its
Configuration Management Program (CMP) was complete for all 88 plant systems,
comprising all Maintenance Rule "in scope" group 1 and 2 systems. As delineated in the
NRC Confirmatory Order governing the Independent Corrective Action Verification Program
(ICAVP), this pronouncement by the licensee declared all 88 systems available for review
and inspection as part of the ICAVP process. During the previous inspection period, the
licensee line management had declared readiness for the start of ICAVP activities. Af ter
concurrence from the licensee's Nuclear Oversight organization, the ICAVP process at -
Millstone Unit 3 commenced on May 27,1997.
As of the end of this inspection period, the NRC had selected all five systems tnat will be
subject to the ICAVP contractor (four "in-scope" systems) and NRC team (one "out-of-
scope" system) review. The last two of the four "in-scope" systems were selected by
random drawing at a public meeting held on July 18,1997 by the Connecticut Nuclear
Energy Advisory Council. The results of the ICAVP review process are made public via the
protocol established with the ICAVP contractor and plan approval; and therefore will not
routinely be documented in the Millstone Special Projects Office combined inspection
reports.
U3.1 Onorationt
U3 01 . Conduct of Operations
01.1 Loss of Scent Fuel Pool Coolina Event Followuo
a. insoection Scoce (71707. 92901)
On June 25,1997, cooling water flow to the spent fuel pool was inadvertently stopped
when the component cooling water and service water systems supporting the in service
("A" train) spent fuel pool cooling heat exchanger were taken out of service as part of
planned outage maintenance activities. With the cessation of forced cooling, the spent fuel
pool water temperature increased approximately 10*F over the following 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />. Based
upon the higher pool temperature reading, observed by a plant equipmcnt operator (PEO)
during routine operations shift rounds, the abnormal equipment lineup was recognized and
spent fuel pool cooling (SFPC) was restored using the in-service components of the
redundant "B" SFPC train. During event followup subsequent to the recovery from the
abnormal spent fuel pool heatup, the NRC inspector reviewed the licensee's root cause
investigation process and independent review team (IRT) interim (draft) report. The
inspector attended an IRT working meeting and discussed findings and facts with both unit
.
.
.
.
23
line management and nuclear oversight personnel. The inspector also reviewed the
operating procedure for the spent fuel pool cooling and purification system.
b. Observations and Findinos
Routine NRC resident inspection of the control room on June 25,1997 identified a spent I
fuel pool tempbrature of less than 90'F. The normal operating procedure directs routine
operation of the SFPC system to maintain pool temperature below 125'F. Since a slight
rise in temperature is anticipated with a train swap, the spent fuel pool temperature
increase that occurred during the remainder of the day and swing shif ts on June 25 would
not have been expected to be recognized as an abnormal condition by the plant operators.
A review of the logs for the Mode 5/6 Daily and Shiftly Control Room Rounds for the period
in question noted that the mid shift on June 26 documented a spent fuel pool temperature
of 90'F on both control board temperature indicators, SFC*Tl27A&B. Since the
documented acceptance criteria for a temperature less than 125'F was met, only operator
cognizance of a rising temperature trend would have identified the loss of spent fuel pool
cooling before it was identified by the PEO on radwaste rounds on the morning of June 26.
Control room operator recognition of such a rising trend was impeded by the practice that a
,
'
new log theet is issued daily for all thrae shifts, commencing on the mid shift. Therefore,
the mid shif t operator did not have the benefit of a visual aid indicating to him when he
filled out the Control Room Rounds sheet for June 26 that the temperature had risen to
l 90*F from the mid-80's temperature indications documented on the previous day's log
l sheet.
The inspector reviewed the Control Room Rounds logs, the computer generated spent fuel
pool temperature plots, the alarm response procedures, the SFPC operating procedure (OP
3305, Revision 15), and examined the control board temperature indicators, discussing
with operators on shif t both the conduct of shift log keeping and the degree of accuracy to
which temperature indications would be recorded. The inspector noted that SFC*Tl27A&B
were marked in 5'F increments, which by common instrumentation and control convention
would limit the degree of accuracy for any temperature readings to step intervals of
approximately 2.5 degrees each. The inspector confirmed that the main control board
alarm for spent fuel pool temperature annunciates at greater than 135'F. It was noted that
the operators appropriately used the emergency operating procedure, EOP 3505A, for
" Loss of Spent Fuel Pool Cooling" to restore an operable cooling flow path once it was
recognized that the system was not correctly aligned. The maximum temperature to which
the spent fuel pool rose during this event was approximately 98'F.
The Unit 3 line management initiated an Event Review Team (ERT) to investigate the root
cause and contributing factors to this event. The Nuclear Oversight organization also
chartered an independent Review Team (IRT) at the request of senior station management
to assess the event, its causes, and the conduct of the ERT. The inspector reviewed the
completed ERT Root Cause Investigation, monitored the IRT conduct of a meeting to
discuss preliminary results of their review, and examined a copy of the IRT interim report.
it was determined that the interim nature of the IRT analysis, findings, and conclusions was
based upon the intent to perform a follow-up assessment of the larger programmatic
aspects of the " Conduct of Operations" at Millstone Station. Both the ERT report and IRT
assur
_ _ _ . _ . . . . ___ . _ . ._ __. _ _ _ . _ . _ _ . _ __ __ _ ._.-. ___
.
d
24 ,
!
interim report documented several corrective action recommendations on specific (e.g., log
keeping) and generic (e.g., configuration control issues) measures that could be
implemented to r' event problem recurrence and enhance future process controls, including
those affecting human performance issues, While some of these corrective actions are
-
directed toward longer term (e.g., corrective action effectiveness, conduct of operations
- standards) enhancements, most recommendations appear that they should be implemented
prior to the restart of the unit.
,
c. Conciusioni
(
The Unit 3 spent fuel poolis designed from a structural standpoint to withstand a
'
temperature of 200'F, has a design limit of 140'F from the standpoint of preservation of
4
the purification components (e.g., resin), has an annunciator alarm setpoint of 135'F, and
is controlled administratively to operate at a temperature of less than or equal to 125'F.
, Therefore, this event, involving the loss of SFPC for approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> and resulting
1- in the heatup of the pool to approximately 98'F, was not significant from a safety related
or design basis considerations. However, given the configuration management
'
ramifications (i.e., the shut down risk impact with a cross train connected system lineup,
the " train swap" control considerations, and the loss of continuity of operator cognizance
.
of how safety related equipment was aligned), this event has significance not only with
respect to the adequacy of current operational and configuration controls but also
management's expectations for operational standards. The former appears to have been
- addressed by the licensee's ERT report, while the latter is in the process of being assessed
'
by the IRT oversight. Several corrective measures have been recommended and a
i
programmatic review of the conduct of operations is planned as an IRT follow up activity.
- The NRC will continue to monitor licensee progress in the assessment of this event, its
4 generic implications upon the adequacy of other programs (e.g., corrective actions, conduct
, of operations), and the implementation of effective corrective measures. This overallissue
will be tracked as an inspector followup item. (IFl 50 423/97 202-03)
U3 07 Quality Assurance in Operations
07.1 Ooerational Oversiaht Activities (SIL ltems 73 & 86)
The inspector continued to routinely meet with Nuclear Oversight personnel to discuss
activities and initiatives in the areas of the corrective action program enhancement, self
'
4
assessments, priorities for unit restart readiness,10 CFR 50.54(f) involvement, and the .
2
conduct of Nuclear Safety Assessment Board (NSAB) meetings. Where appropriate,
Nuclear Oversight surveillance, audit, and special reports were reviewed to assess the level
of QA involvement in the performance of routine activities by the Unit 3 line management,
as well as to determine progress in the corrective measures taken for known problem
areas. Specfically during this inspection, the inspector reviewed the following documents
-
and performance of assessment / evaluations, that provided evidence of continued
management attention to strengthening the Nuclear Oversight function at Millstone Station.
4
- e Dissemination of site briefing information on the conduct of an Independent
- Assessment of Nuclear Oversight by a review team of industry consultants and
n. e ~ w
. 25
personnel from other nuclear utilities. This team performed a two-week, onsite
assessment commencing on June 19,1997 and conducted a preliminary exit
briefing with senior NU management before departing the station. This exit meeting
was observed by an NRC Special Projects Office Branch Chief.
- Issuance of a self assessment report for the first quarter of 1997, documenting the
Nuclear Oversight Performance Evaluation (PE) Department's strategic plan
development and assessment of organizational effectiveness. Since the PE group
,
was formed in December 1996, this selfessessment evaluated the infrastructure
and organizational effectiveness of the department using interviews, bench marking,
and criticalinternal assessments.
- Documentation of a Nuclear Oversight Operational Readiness Assessment Plan for
Urlt 3. This document discusses the approach and process by which verification
activities will be conducted to ensure safe operution of the unit, the effective
functioning of the line organizations, and the adequacy of preparations for the
resumption of power operatior.s after the extended shutdown.
- Publishing Northeast Utilities Nuclear Safety Standards and Expectations by the
President and Chief Executive Officer of the NU Nuclear Group. The principles
discussed in this document appear directed to providing Nuclear Group personnel
with management's focus on the safety of operations and other critical, mission-
driven organizational requirements.
- Establishment of the Independent Review Team concept, including IRT staff
organization and resources, goals, and the use of processes in event evaluations.
The IRT process was utilized to further assess the loss of spent fuel pool cooling
discussed in Section 01.1 of this inspection report.
- lssuance of a significant number of condition reports (CRs), along with appropriate
use of its stop-work authority, by the Nuclear Oversight Organization during this
report period. An increasing level of Nuclear Oversight involvement in both problem
identification and recommendations for improvement is evident not only in the CRs,
but also in audit and surveillance reports, as well as routine and special management
meeting participation,
in addition to review of the above program initiatives and assessment activities, the
inspector specifically evaluated Nuclear Oversight and senior licensee management actions
to address concerns with personnel overtime controls. The inspector noted that some
overtime program violations had been recurring at Unit 3 smce early 1996. The Nuclear
Safety Engineering Group conducted an evaluation of the overtime controls at Millstone
Station to determine if changes to Nuclear Group Procedure, NGP 1.09, " Overtime Controls
for All Personnel at Millstone Station," were necessary. Based upon this review and
issuance of a Level 1 CR to collectively address the identified overtime violations, the
licensee determined that a revision to NGP 1.09 was required. On .luly 23,1997, the
station operations review committeo (SORC) approved revision 8 to NGP 1.09 and the new
overtime control provisions became effective on July 25,1997.
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - - -
26
.
The inspector questioned when an updated Millstone Unit 3 Operational Readiness Plan
(ORP) would be issued, since the existing revision 3 had been issued in November 1996
and appeared to be outdated. The inspector noted that d NSAB had also commented at a
board meeting conducted in May 1997 about the " obsolete" nature of the current ORP. It
was recognized by the NRC that since November 1996, an interim "Re::overy Plan * has
been published; however, the protracted length of time since the last ORP revision
encompassed a number of management changes and corresponding adjustments to the
plan. On July 24,1997, a new Unit 3 ORP (revision 4) was issued, bringing up to date the
current licensee philosophy on the restart issues management and restart eternents
recognized to prepare Unit 3 for operational readiness and subsequent startup and power
ascension activities.
Overall, the Nuclear Oversight organization appeared to be actively involved in quality
assurance and assessment activities directed toward effective corrective actions for
i identified problem areas and program enhancements to improve future operations. The
initiatives noted above attest to a more active role by Nuclear Oversight in dealing with line
performance. However, while the routine QA and oversight reports document cognizance
of the areas which represent the most significant challenges to improving performance, the
ability of Nuclear Oversight to effect positive changes has not yet been fully demonstrated.
, While examples of success, as noted above, do exist, significant challenges were noted by
I the NRC to remain in such areas as corrective action effectiveness, training enhancements,
and plant configuration management controls, as are discussed in technical details in other
sections of this report, Progress in the areas of QA/ Oversight program improvement will
continue to be tracked by the NRC as part of SIL ltem 73, while needed training program
enhancements, discussed further in Section M4.1 of this inspection report, will be reviewed
as part of SIL ltem 86.
U3 08 Miscellaneous Operations issues (92700)
08.1 Technical Soecification (TS) Noncomoliance
a, ID30ection Scoce
Several recently issued licensee event reports (LERs) have dealt with TS noncompliance
issues. The inspector reviewed the LERs for root cause and safety significance
determinations and adequacy of corrective actions. The inspector also verified that the
reporting requirements of 10CFR 50.73 had been met,
b. Observations and Findinas
(Closed) LER 50-423/96-34
This LER documented that the residual heat removal (RHR) pump suction relief valves were
not set in accordance with TS 3.4.9.3. The TS required the RHR reliefs be set at 450 psig
in order to provide over pressure protection when the reactor coolant system cold leg
temperature was less than 350*F. The actual lift pressure for the RHR suction reliefs is
440 psig. The lif t pressure for the valves, as documented in the original design change and
_ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
a
2 7 .-
.
the subsequent set point calculation, is 440 psig. A TS change request was processed and
submitted to the NRC for review to change the value to between 426.8 and 453.2 psig,
The inspector verified the licensee had entered the applicable TS action statement and had
not credited the RHR suction reliefs as a means to satisfy TS 3.4.9.3. In addition, the
licenseo had issued proposed technical specification change request (PTSCR) 314 96 to
change the RHR suction relief setpoint. This request was approved on July 10,1997.
(Closed) LER 50 423/97 14
This LER documents that both trains of the control room envelope pressurization system
(CREPS) were inoperable due to instrument air valves 3 IAS V644/V725 being found out of-
position. These valves supply air to solenoid operated valves which control air operated
dampers in the control building. The solenoids are not qualified as category 1 equipment
and therefore, it must be postulated that they fall in the most adverse position. This
creates the potential for a breach of the control room envelope which would render the
CREPS inoperable. The air valves had been opened to allow purging of the cable spreading
room and apparently had not been closed after completion of the evolution.
The licensee promptly restored the air valves to their required position and revised the
procedure to correct the deficiencies. The inspector verified that procedure OP 3314F
was revised to restore the valves to their normally closed position.
(Closed) LER S0-423/97 23
This LER documents that the main steam isolation valves had not been tested in
accordance with the literal requirements contained in the TS. The Technical specifications
require that the valves be demonstrated operable by verifying full closure within 10
seconds in modes 1, 2, and 3 when tested pursuant to TS 4.0.5. Relief from the
requirement to perform a full stroke test during power operation had,been granted by the
NRC in the licensee's inservice test program; however, the licensee had not submitted a TS
change request to delete this requirement from TS. The inspector verified the licensee had
initiated a PTSCR to eliminate the requirement for full stroke testing the MSIVs in modes 1
and 2.
(Closed) LER 50-423/97-24
This LER documents that the engineered safeguards building noble gas activity monitor
(3HVQ'RE49) was inoperable and that best efforts to repair the monitor had not been
initiated in accordance with TS 3.3.3.10. The radiation monitor was declared inoperable
since it was incapable of measuring an effluent concentration as low as 1.0 E 06 uCi/cc.
The instrument had been purged by operations personnel due to the receipt of spurious
alarms. The radiation monitor design contains a feature where, upon completion of a
purge, a new background level is automatically measured and entered into the circuitry.
Review of the database entries indicated that a background value of 1.01 E 06 uCi/cc was
entered. Background readings at this location are normally 1.0 E 08 to 1.0 E-07 uCi/cc.
The high background level was attributed to electromagnetic interference from welding
. . - _ _ - - .. .-
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28
.
activities in the general area. The incorrect background level prevented the monitor from
meeting the sensitivity requirements specified in the TS bases.
Interim corrective actions included revising operations procedure OP 3250.62 to enter a
zero background level reading after purging the radiation monitor, and chemistry procedure
SP 3867 to verify zero background after completion of surveillance activities. Long term
corrective actions include a review to evaluate the removal of the automatic background
subtraction feature associeed with 3HVQ'RE49 and other radiation monitors.
The inspector verified that procedural changes had been made to the operations and
chemistry procedures to zero the background level after purging and completion of the
surveillance in addition, an engineering work request was initiated to delete the automatic
background subtraction feature from applicable radiation monitors.
(Closed) LER 50-423/97-26
This LER documents that ASME Section XI required examinations on some service water
supports had not been re performed during the subsequent refueling outage, for supports
that initially f ailed inservice inspection (ISI) examinations during 1989. The licensee had '
originally assumed that the supports were located in areas where performance of the
examinations was impractical.10CFR 50.55a provides for relief, when justified. However,
relief was not spec'.fically requested to allow excluding the examination of these
component supports. The f ailure to perform these examinations is a condition prohibited
by TS 4.0.5. Subsequent inspections by the licensee revealed that the supports were
acceptable.
As corrective action, the licensee revised the ISI program documents to include ASME
Section XI requirements for performing additional and successive examinations, and
included guidance for requesting relief in accordance with 10CFR 50.55a. The inspector
verified that the ISI Program Manual was revised to capture these requirements,
c. Conclusions
The LERs discuss conditions prohibited by TS. Further NRC review of each LER established
that while the licensee's operational activities were proper evolutions, literal compliance
with the plant TS had not been maintained. Based on the above corrective actions and the
low safety significance of the issues, these licensee-identified and corrected violations are
being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NBC
Enforcement Poliev. The listed LERs are closed.
However, the closure of the LERs does not address the generic concern for TS compliance.
A review of LERs issued as of April 1996 revealed that there have been a number of LERs
that have dealt with TS compliance problems relating to questionable interpretations. This
area is of current interest for further NRC review and is included as an NRC followup
activity; documented as Significant items List (SIL) item 70.
.. .
..
_ - _ _ _ _ _ _ _ _
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.
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29
U3.Il Maintenance
U3 M1 Conduct of Maintenance
M 1.1 General Comments
The inspectors' determined that the maintenance and surveillance activities observed were
properly performed.
M1.2 inservice Test Prooram Review
a. insoection Scone (73756. Tl 2515110)
The inspectors evaluated the effectiveness of Northeast Nuclear Energy Company's
(NNECO) inservice test program for safety related pumps and valves at Millstone Unit 3.
The inspectors focused primarily on components in the auxiliary feedwater (AFW),
interrnediate head safety injection (IHSI), and reactor plant component cooling water
systems. These risk significant systems are needed to prevent or to mitigate the dominant
core damage frequency events identified in the Millstone Unit 3 Individual Plant
Examination.
The)urposes of inservice testing (IST) are to assess the operational readiness of pumps
and valves, to detect degradation that might affect component operability, and to maintain
safety margins with provisions for increased surveillance and corrective action. The
requirements for IST are contained in Millstone Unit 3, TS 4.0.5, which requires testing in
accordance with 10 CFR 50.55a, " Codes and Standards," and Section XI of the American
Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code). The
inspectors reviewed administrative and surveillance procedures, engineering evaluations
and calculations, test rest,lts, and LER's germane to the Millstone Unit 3 IST program.
b. Observations and Findinos
Millstone 3 Unit is implementing the first 10-year interval of the IST program, which is
based on Section XI of the Code (1983 Edition). However, pursuant to 10 CFR
50.55a(f)(4)(iv), NNECO is currently upgrading its program for the second 10-year interval >
to the 1989 Code Edition which includes ASME/ ANSI OMa-1988, " Inservice Testing of
Pumps and Valves in Light Water Reactor Power Plants," Part 6 (OM 6) for pumps, Part 10
(OM 10) of ASME/ ANSI OMa-1988 for valves, and ASME/ ANSI OM-1,1987 for pressure
relief devices.
M1.3 IST Prooram Scoce -
a. insoection Scone
The inspector used NNECO's IST program submittals, the Updated Final Safety Analysis
Report (UFSAR) and technical specifications, design basis documents, system drawings,
_ ~_ _ _ ._
.
30 .
and surveillance procedures to verify that the pumps and valves in the selected systems
that perform a safety function were included in the IST program.
b. Observations and Findinas
During an IST program review conducted in June 1996 on part of their response to a 10
CFR 50.54f letter, the licensee identified 75 valves that were not included in the program,
end 45 instances involving valves in which all the safety functions were not tested
periodically. Components in thirteen safety-related systems were involved, including the
reactor coolant safety injection, service water, containment recirculetion spray, and
emergency diesel generator systems. The licensee reported the condition to the NRC in
Licensee Event Reports 50-423/96-21 and 50-423/96 24. The inspector conducted a
detailed review of the selected systems to confirm that the licensee had changed the
program scope to include all of the required components and tests. The inspector found
that with the exception of tesidual heat removal pump seal cooler relief valves
3CCP*RV239A/B and resioual heat removal heat exchanger relief valves 3CCP'RV64A/B,
the revised IST program satisfied the scope statements of Article IWV-1100, and Section
1.1 of OM 10 and OM-1,
The licensee determined that the program scope discrepancies had been due to lack of
management commitment to the program, and inadequate program monitoring and self-
assessment. Corrective actions included staff augmentation, development and
implementation of detailed administrative procedures and project instructions, and
compilation of a component level design-basis document detailing the bases for decisions
regarding program scope and test requirements, in the document, the safety functions of
each component are traced back to the TS, UFSAR, and design documents and
calculations. The design-basis scope document is not required by the Code and was a
good licensee initiative. The inspector also noted that a new project instruction for periodic
IST program suif-cssessments was included in the new program. The inspector found that
the licensee's corrective actions addressed the root causes of the program deficiencies.
Resolution of specific test discrepancies were being tracked under Action Request
96036464. Twenty-nine major items encompassing 143 action items were being tracked.
The inspector reviewed approximately half of the major items covering 112 components
and tests. Most of the action items involving surveillance procedure and test schedule
revisions were completed. However, due to the operating condition of the plant, few tests
had been performed at the time of the inspection. The inspector determined that no test
failures had yet occurred, and that the outstanding tests were being tracked adequately.
The licensee has committed to update LER 96-21 with the results of the new tests.
c. Conclusions
The IST program scope problems constituted a violation of 10 CFR 50.55a(f), which
requires inservice testing of ASME Code Class components as defined in Article IWV-1100
and Section 1.1 of OM-10 and OM-1. The causes for the program failures were being
addressed adequately, and individual test discrepancies were being tracked and resolved
l
l
'
l
'
. 31
appropriately. Therefore, this licensee identified and corrected violation will not be cited
since the criteria of Section Vll.B.1 of the NRC Enforcement Policy were met.
M 1.4 (Uodatel SIL ltem 53 - ARCOR Coatino
a. Insoection Scone (627071 l
The licensee developed special procedure SPROC 97 3-4, "SpecialInspection and Testing
of Se,rvice Water Piping Previously Lined with ARCOR Epoxy," to verify the quality of the
ARCOR coating applied to the internal surf ace of the service water (SW) piping. This
testing was being performed to establish baseline adhesion values for the ARCOR coating,
and to determine the condition of the existing ARCOR coating within the SW system. The
inspector witnessed portions of the testing on the ARCOR test plates and inspection of
selected SW spool pieces.
b. Observations and Findinos
The test program to establish the baseline adhesion value for ARCOR coatings consisted of
performing pull-tests to failure of the various ARCOR test plates. The plates were
fabricated with proper intercoat, heated intercoat, contaminated intercoat, and a releasing
agent intercoat. Testing revealed that the ARCOR coating could withstand a force of 2000
psiif the ARCOR coatings were properly applied; whereas contaminated surf a':es could
only withstand a force of approximately 500 psi before the ARCOR coating delaminated.
Based on these bounding values, the licensee performed pull tests (a non-destructive test
method) on the ARCOR coated spool pieces installed in the field to 1000 psi to
demonstrate that the ARCOR coatings were properly applied. Each ARCOR coated spool
piece was tested at each end and at the approximate mid-point of the spool at the 90,180,
270, and 360 radial degree locations.
Testing of the "B" train SW revealed no ARCOR delamination from the pull testing to 1000
psi. However, during the removal of one of the pull tabs, a small piece of the ARCOR top
coat delaminated. The licensee was subsequently able to remove an area of approximately
one square foot from this area indicating that it was not properly bonded. Condition Report
(CR) M3-97-1729 was written to document this condition. A couple of days later, another
coating failure occurred during the removal of a pull tab for a spool that had recently been
coated.
Investigation into the f ailure for the newly applied ARCOR coating revealed that the cure
time had been exceeded, in addition, one of the environmental conditions (humidity)
specified in maintenance procedure MP 3710C, " Application of Linings to Plant Systems
Subject to Salt Water immersion," was not maintained. A review of maintenance records
of other recently coated spool pieces revealed that the cure time had been exceeded for
five other SW spools. A voluntary stop work was initiated on all Unit 3 SW coating
application due to these application errors.
The SW spool pieces identified as having application errors were re-tested by "X-CUT" (a
destructive test method) to determine the quality of the ARCOR coating. No additional
_ - - _ _ _ _ _ - _ - - - .
32
'
problems were noted. As a result of the failures of the ARCOR coating during removal of
the pull tabs, the licensee concluded that they could not demonstrate that the ARCOR
coating on the SW spools tested by the pull test methodology had been properly applied.
All but one ARCOR coated spools in the "B" train of SW have since been tested by "X-
CUT;" no other delsmination failures occurred.
The licensee concluded that the root cause for the suspected improper application of the
ARCOR coating was procedure non-compliance. The procedure for application was not
followed as written due to incorrect assumptions made by the painters and contractor
inspectors. The ARCOR re-coat window time was incorrectly assumed to be seven hours
or thumb nail (check for ability to cause indentation in product indication not fully cured).
The environmental condition control was recognized as being lost, however the craft
reestablished the conditions and continued the coating application without obtaining any
further guidance.
The inspector reviewed procedure MP 3710C and the maintenarice records for ARCOR
coating application and noted that severalindividuals had not followed the procedure,
i
investigation revealed that the SW spools in question all exceeded the 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> maximum
overcoat time by 45 minutes to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 41 minutes. Procedure step 4.5.2 states that
the re-coat window is determined from the product specific technique sheet (PSTS). The
PSTS maximum acceptable overcoat condition is 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> or thumb nail test with no
indentation, whichever is less. The collective procedural noncompliance indicates both an
individual and departmental control performance problem. The f ailure to follow procedures
constitutes a violation of technical specification 6.8.1. (VIO 50-42397 202-04)
c. Conclusions
A review of ARCOR coating application work orders revealed that on six separate
occasions the recoat window was exceeded, These examples demonstrate a low standard
for following procedures and a lack of management oversight for this critical evolution.
The condition of existing ARCOR coating within the SW system and the potential effect of
ARCOR delamination on safety-related components is under NRC review an is included as
an Independent Corrective Action Verification Program followup activity; this is
documented as Significant items List (SIL) Item 53.
M1.5 Service Water Class ill Pioina Retest
a. Insoection Scooe (62707)
The inspector reviewed maintenance activity M3-96-18746, replacement of service water
(SW) piping to ventilation unit 3HVO*ACU2A, to ensure that proper retest requirements
were specified.
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33
b. Observations and Findinajl
The work activity consisted of the replacement of the SW ventilation piping; a 1 1/2 inch
nominal pipe size (NPS), ASME Code Class lll pipe. A review of the work order and ASME
Section XI repair and replacement plan revealed that the licensee had invoked the use of
code case N-4161, " Alternative Pressure Test Requirements for Weld Repairs or
Installation of Repitce. ment item by Welding, Class 1,2,3,Section XI, Decision 1." The
work activity required only a visual examination (VT 2) of the affected mechanical joints at
normal operating pressure and temperature.
Code case N-4161 specifies that a system leak test, in lieu of a hydrostatic pressure test,
may be performed provided that a non-destructive examination (NDE) is performed in
accordance with Section XI with a VT-2.
ASME Section XI requires that after welding repairs on the pressure retaining boundary of
Class lll piping, either a hydrostatic test or non-destructive testing be performed. In a
memorandum, dated January 18,1995, the NRC approved the use of code case N-4161
for Unit 3 as an alternative to the provisions of ASME Code Section XI, thus eliminating the
'
requirement to perform a hydrostatic pressure test. The NRC authorized the use of this
code case provided that additional surface examinations were performed on the root (pass)
layer of butt and socket welds on the pressure retaining boundary of Class 3 components
_
when the surface examination method is used in accordance with Section til of the ASME
Code.
NU memorandum, CES 95163, dated 2/16/95 attempted to clarify the guidance provided
by the NRC. The guidance indicated that a surf ace examination would be required on
Class 3 piping when Section XI required surface examinations of the welds.Section XI
Section ND 5222 states that a surface examination is not required on two inch NPS or
less. The welds in question were for piping of 1 1/2 inches.
The inspector discussed with the licensee the interpretation of the use of the code case
provision. The licensee stated that their interpretation was based on discussions with the
NRC in 1995. The inspector contacted NRR for clarification of this issue to determine what
was the intent of the 1995 letter. The NRC reviewed this issue and concluded that a
system leak check was adequate for Class lil NPS two inches or less.- The NRC staff did
not intend that the licensee apply additional surface examination of the root pass to weld
joints two inch NPS and smaller as a condition for approval of the code case.
c. Conclusion
Code case N 4161 was approved for use at Unit 3 by the NRC in a letter dated January
.18,1995. The licensee's interpretation and use of the code case for Class ll1 piping was
proper. The retest specified for work activity M3 96-18746 was adequate.
.
34
.
U3 M3 Maintenance Procedures and Documentation
M3.1 Testino of Safetv/ Relief Valves
a. insoection Scone
The IST program invoked the requirements of ANSI /ASME PTC 25.3, Safety and Relief
Valves / Performance Test Codes, for testing safety / relief valves. As permitted by 10 CFR
50.55a(f)(4)(iv), however, the licensee's procedures also referenced Operation and
Maintenance (OM) 1 1987. The inspector reviewed licensee and vendor procedures
against the scope, test methodology, and corrective action requirements contained in these
documents.-
b. Observations and Findinos
The licensee categorized pressurizer power operated relief valves (PORVs) 3RCS*PCV455A
and 3RCS*PCV456 as Category B/C valves in their IST program, and tested the valves in
accordance with TS 4.4.4.1, Relief Valves,4.4.9.3.1, Overpressure Protection System,
and Section 7.3.1.2 of OM 1. The tests involved determination of operability of pressure
sensing and valve actuation equipment, and verification of the operation and electrical
characteristics of the valve position indicators. Calibration of the PORV actuation
instrument channels was performed once per refueling interval, and the PORVs were
operated through one complete cycle of full travel with the blocking valves open while the
plant was in hot standby or hot shutdown.
NRC Information Notice 89-32, Surveillance Testing of Low Temperature Overpressure
Protection (LTOP) Systems, documented that some licensees did not translate the PORV
stroke times assumed in their LTOP analyses into IST surveillance requirements. Licensee
calculation NM 027 ALL, Active Valve Response Times, assigned a PORV open stroke time
limit of two seconds based on safety grade cold shutdown system requirements. However,
the licensee's' cold overpressure mitigation (COM) system analysis assumed a more
restrictive stroke time limit. Westinghouse memorandum NSD SAE ESI 97-167, dated
March 19,1997, specified an opening requirement of 0.85 seconds. Surveillance
procedure SP 3601B.2, Reactor Coolant System Vent Path Operability Check, specified an
acceptance criterion of one second. The inspector verified that the acceptance criterion
satisfied Section IWV-3413(b) of the Code, which requires PORV stroke times of ten
seconds or less to be measured to the nearest second. The licensee will need to update
calculation NM-027 ALL to reflect the more restrictive criterion.
The inspector reviewed procedure SP 3712A, Pressurizer Code Safety Valve Surveillance
Testing, and Wyle Laboratories Report No. 44656-0, Recertification Test Program For
Millstone Nuclear Plant, Unit 3, dated June 4,1995. The acceptance criteria for "as-
-
found" and "as-lef t" set pressure tests were plus or minus 3 percent and plus or minus 1
-
percent, respectively. The criteria conformed to TS 3.4.42 requirements and met or
exceeded the requirements of the Code. The inspector noted that step 2.1.2(b) of
procedure SP 3712A specified a five minute waiting period between consecutive valve lifts
instead of the minimum 10 minute period required by Section 8.1.1.8 of OM-1. The
_ _ _ _ _ .
.
35
licensee provided an NRC approved relief request for the deviation. The licensee's
surveillance procedure and the vendor tests conformed with the requirements of PTC 25.3
and OM 1.
The licensee tests the main steam safety valves in place using a hydraulic lift assist
i
(hydroset) device per procedure SP 3712G, Main Steam Code Safety Valve Surveillance
Testing. This 1nethod is sanctioned in PTC 25.3 and OM 1. A sample of main steam
safety valves also were tested at Wyle Laboratories in 1997. The inspector reviewed test
results and Wyle Laboratories Procedure No.1071, Testing of Dresser Spring-Operated
Main Steam Safety Relief Valves, and found that the requirements of TS 3.7.1.1 and OM 1
were met. The licensee properly evaluated system operability when "as found" tests failed
to meet the specified acceptance criteria.
Step 4.1.16 of procedure SP 3712G specifies that hydroset pressure be increased until the
safety valve begins to simmer. A preceding note cautions that the valves not be allowed
to " pop". The licensee noted that Section 2.7 of PTC 25.3 defines " simmer" as an audible
or visible escape of fluid at an inlet static pressure below the popping pressure and at no
measurable capacity. Thus, if the actual difference between the valve's simmer point and
set pressure were great enough (e.g. greater than one percent of set pressure), the current
<
test method would be nonconservative. The licensee initiated condition report M2-97-
0955/M3 971758 to evaluate the condition. The inspector did not consider it likely that
the difference would hate a significant effect on valve performance during a rapid
overpressure transient. However, the issue was relevant to literal compliance wi;h the
Code, and had potentially generic consequences regarding the validity of the test method.
The licensee's observation evidenced a good questioning attitude towards safety and Code
compliance, inspection followup item (IFl 50 423/97 202-05) is opened to review the
results of the licensee's evaluation of this matter.
Other Code Class 2 and 3 relief valves were tested periodically in accordance with
maintenance procedure MP 3762WD, Setting and Testing Relief Valves. The inspector
reviewed the procedure and found that it satisfied the requirements of OM 1 overall. The
procedure stated that no set pressure corrections for ambient temperature were needed
when normal system operating temperature was less than 250 degrees Fahrenheit ('F),
while the set pressure setting was to be increased by three percent where system
operating temperature was between 250'F and 1000*F. Section 8.1.3.5 of OM-1 requires
the ambient temperature of a relief valve's operating environment to be simulated during
the set pressure test, if the effect of ambient temperature on set pressure can be
established for a particular valve type, then the valve may be pressure tested using an
ambient temperature different from the operating ambient temperature. Correlations
between the operating and testing ambient temperatures must be established by test per-
Sections 8.3.2 and 8.3.3 of OM-1. The ASME has found that some relief valve
manufacturers have no engineering or test bases for the correlations that they provide, and
has established a task force to determine standardized criteria for the correlations. The -
licensee ultimately will need to establish a technical basis for its set pressure adjustment to
be in full compliance with OM-1. However, since the difference between the " cold" (i.e.
bench test) and operating set pressures typically is small, the inspector concluded that the
licensee's approach was not an immediate safety concern.
___. . _ _ - _ - _ _ _ _ _ _ _ - _ _ _ - _ - _ _ -
36 .
c. Conclusions
Pressurizer safety / relief valves and main steam safety valves were tested in accordance
with Code requirements. However, a followup item was opened regarding the potential
that relief valve testing to the valve " simmer" point may be nonconservative. For other
Coda Class 2 and 3 relief valves, set pressure adjustments made to account for differences
in bench test and normal operating ambient temperatures need to be justified by test per
OM 1. .
M3.2 Eump Testina
a. Insoection Scom
The inspectors reviewed surveillance procedures and performance records against OM-6
requirements for test periodicity, quantities measured, and allowable ranges. The review
l included pumps in the auxiliary feedwater, intermediate and low pressure safety injection,
L and reactor plant component cooling water systems,
b. Observations and Findinas
.
Procedure EN 31121, IST Pump Operational Readiness Evaluation, contained the
acceptance criteria for the safety-related pumps at Millstone 3. The inspector verified that
I the hydraulic and vibration criteria established by the licensee conformed to the limits in
Table 3 of OM-6. The licensee's vibration monitoring program exceeded Code
requirements by including the pump drivers, which are explicitly excluded from the program
scope in Section 1.2(a) of OM-6. The procedure also contained guidance pertaining to the
required corrective actions if a pump entered the alert or required action ranges. A note
preceding step 4.4.4 of the procedure stated that new reference values could be
. established as corrective action for a pump that was operating in the alert range. This
guidance was inconsistent with Sections 4.3 and 4.5 of OM 6, which state, respectively,
that reference values shall only be established when a pump is known to be operating
acceptably, and that additional reference values may be established only if IST of the
existing' set of reference values is acceptable. The licensee agreed with the inspector's
observation and initiated a procedure change to delete the note from the procedure. The
inspector noted that the provision had not been invoked for any pumps at Millstone 3.
The inspector noted that the charging and intermediate head safety injection pump
performance curves contained in Attachment 4 of procedure EN 31121 differed from the-
curves (Figures 6.3-4 and 6.3-5, respectively) in the UFSAR. The licensee explained that
the UFSAR figures were based on system flow calculations used in the accident analyses,
while the curves in the engineering procedures were actual pump performance curves
developed during pre-service testing. The inspector had no further questions regarding the
curves.
For IST of pumps, Section 5.2 of OM-6 requires that the resistance of the system shall be
varied until either the flow rate or [ differential] pressure equals the reference value. Where
system resistance cannot be varied, flow rate and pressure shall be determined and
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. . . .
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.
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37
compared to their respective reference values. Clarification provided in Section 5.3 of
NUREG 1482 states that the Code does not nilow for variance from a fixed reference
value. In order to ensure that periodic tests are performed under repeatable conditions, the
NRC has determined that a tolerance of +/ 2 percent (%) of the reference value may be )
used without NRC approval. For a tolerance greater than +/ 2%, compensatory i
adjustments may be made to the acceptance criteria, or an evaluation may be performed, I
justifying the greater tolerance. Where resistance cannot be varied, it is acceptable to use I
the broader criteria in Table 3b of OM 6 as the tolerance.
'
Most of the safety-related pumps at Millstone 3 are tested through fixed resistance
minimum flow lines that are capable of, but were not designed for, adjusting the flow rates.
The licensee identified that for the charging, intermediate head safety injection, and
feedwater pumps it could not meet the tolerance band prescribed in the NUREG due to
large instrument fluctuations. In pump-specific evaluations, the licensee justified reference
value ranges of up to 7.2%/+ 10% of the reference values based on the minimum flow
lines being fixed resistance flow paths. Also, since the reference values were close to the
minimum flow rates required for pump protection, the licensee determined that throttling to
attain a tighter tolerance band would be imprudent.
The inspector agreed that throttling the minimum flow rate may be undesirable. However,
l it did not appear that the licensee had considered fully the options to reduce the instrument
fluctuations discussed in Section 4.6.1.5 of OM-6, including use 01 symmetrical damping
devices, instrument line snubbers, or throttling small gage valves in the instrument lines.
The inspector concluded that since it was possible to adjust the flow rates through the
minimum flow lines, although undesirable, the licensee needed to request NRC relief to use
the broader tolerance bands for these pumps.
The inspector also found that the licensee had changed the IST procedure for the
emergency diesel generator fuel oil transfer pumps to no longer adjust pump discherge flow
to attain the required tolerance. The change was made to reduce operator burden and to
avoid having to declare the diesel generators inoperable during IST. As discussed in GL 87-
09, Sections 3.0 and 4.0 Of The Standard Technical Specifications On The Applicability Of
Limiting Conditions For Operation and Surveillance Requirements, and Section 3.1.2 of
NUREG 1482, entry into a TS limiting condition for operation is not itself adequate
justification for deviating from Code requirements.- The licensee will need to provide
additional justification for using a broader reference value tolerance in a relief request to the
NRC, or take other actions to meet the tolerance band required by the Code. The licensee
agreed to evaluate means to reduce the instrument fluctuations, or to request relief from
the Code requirement,
c. Conclusions
Acceptance criteria established for IST of safety-related pumps met or exceeded Code
requirements. Equipment or procedure changes will be needed to meet Code requirements
for repeatability of test reference values, or NRC relief to use broader tolerance bands will
be needed.
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1
38 ,
M3.3 Valve Testing
a. Insoection Scooe
The inspector reviewed surveillance procedures, methods, and acceptance criteria for
several types of valves in the IST program. In addition, the inspectors reviewed the
licensee's treatment of reactor coolant system pressure isolation valves,
b. Observations and Findinas
Power-Ocerated Valve Exercise Tests
Articles IWV 3413(a) and Section 4.2.1.4(a) of OM 10 require limiting values of full stroke
time to be established. The inspector reviewed surveillance procedure acceptance criteria
for power-operated valve stroke times against calculation NM-027 ALL, Active Valve
Response Times: Technical Requirements Manual 3TRM 3.6.3, Containment Isolation
Valves; and UFSAR Table 6.2-65, Containment isolation Valves and verified that the
limiting values selected by the licensee were appropriate. Where not specified in accident
analyses or other design / licensing basis documents, limiting values were assigned based on
a multiple of the reference value stroke time and the physical characteristics of the valve.
The licensee's method in these cases was technically justified and satisfied the Code
requirement. The inspector noted a discrepancy involving charging pump safety injection
isolation valves 3SlH*MV8801 A/B in which the close stroke time limits in the TRM and the
UFSAR table differed. The licensee also had identified the error and was processing a
change to the UF3AR to correct the condition,
The licensee established stroke time reference values based on the average of three stroke
times taken when the valves were known to be in good condition. This method was
consistent with industry practice and Section 3.3 of OM 10. The IST program was in
transition from S9ction XI of the 1983 Code Edition to OM 10. The inspector verified that
the reduction in the stroke time limit for electric motor-operated valves with stroke times
greater than 10 seconds was being implemented in the surveillance procedures.
The inspector noted during review of procedure SP 3608.6, Safety injection System Valve
Operability Test, that the licensee exercised and timed both the open and closed strokes of
many valves that had safety functions in only one direction. This practice exceeded Code
requirements and provided additionalinformation for performance trending of power-
operated valves.
The stroke time tests of motor-operated valves 3SlH*MV8801 A/B were performed using a
motor power monitoring diagnostic system that is installed temporarily at the remote motor
control centers. This method differs from the customary IST practice of using remote valve
position indicating lights, and provides additional information regarding valve performance.
Stroke time was defined in the procedure as the period between maximum motor inrush
current and torque switch trip. The inspector noted that the method could result in longer
stroke times than those derived from valve position indication lamps that are actuated by
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_
39
limit switches. However, this f actor likely is offset by the elimination of the operator
response time lag inherent in using a stop watch.
Article IWV-3300 and Section 4.1 of OM 10 require remote valve position indicators to be
verified by local observation of valves at least once every two years. In Section 4.2,6 of
NUREG 1482, the NRC clarified that the requirement applies only to remote indicators that
are used !n exercising and stroke timing power operated valves. The inspector considered
that the requirement applied to the motor power monitor as well, and noted that the
surveillance procedure provided for the verification.
Check Valve Testina
Check valves in the selected systems were categorized properly in the licensee's program
as Category A or A/C valves. Full flow testing of check valves was performed where
practical under verified accident flow conditions contained in the TS, UFSAR, or other
design documents, as specified in Position 1 of Generic Letter 89-04, Guidance On
Developing Acceptable Inservice Test Programs. Quarterly partial flow tests were followed
up during cold shutdowns or refueling outages with full flow tests, disassembly and
inspection, or nonintrusive techniques. For disassembly and inspection, the licensee
followed the guidance contained in Position 2 of GL 89-04 for grouping and corrective
action. The licensee's methods for verifying check valve closure on cessation of flow met
the requirements of Article IWV 3522(a) for verification by positive means.
Procedure SP 3608.6, Refuel Full Stroke Testing of SlH Header Check Valves, was utilized
to exercise the intermediate head safety injection system injection header check valves.
The procedure measured flow only in the main headers vice through the individual branch
lines, Thus, flow rate through the branch line check valves was not verified, and
nonintrusive test techniques were used to verify valve obturator position. The inspector
reviewed procedures SA 97718, Acoustic and Magnetic Non-intrusive Check Valve
Analysis, SA 95923, Non-Intrusive Check Valve Testing Data Collection, and data traces
recorded during the performance of procedure SP 3608.6 in May 1995. The traces clearly
showed the check valves hitting their backstops, and seating after cessation of flow.
,
As discussed in Section 4.1.2 of NUREG-1482, the NRC has determined that use of
nonintrusive techniques is acceptable as another " positive means" of verifying that check
valves are full stroke exercised within the meaning of the Code. To substantiate the
validity of the method, the licensee must address and document the items enumerated in
Position 1 of GL 89-04 in its IST program, including: (1) The impracticality of performing a
full flow test; (2) A description and summary of the alternative technique used; (3) A
description of the method and results of the program used to qualify the method to Code ,
requirements; (4) A description of the basis used to verify that the baseline data has been
generated when the valve is known to be in good working order; and, (5) A description of
the basis for the acceptance criteria for the alternate method, and the corrective action to
be taken if the acceptance criteria are not met. While the licensee's procedures and the
quality of the data supported their use of nonintrusive test methods, the licensee will need
to address explicitly the items listed in Position 1 of GL 89-04 in their IST program
document. The inspector noted that the licensee also identified this issue during their
-
.
40
1996 review of the Millstone 3 IST program, tracked in Condition Report item
9603646405, and initiated action to complete the required items.
Reactor Coolant Pressure Isolation Valve Testing
The operational and functional requirements of the pressure isolation valves at Millstone 3
are contained in TS 3.4.6.2.f. The TS imposes maximum leakage rates on the check
valves located between the reactor coolant system and contiguous low pressure systems in
order to ensure that the leakage rates will not exceed the pressure relief capacity of the
relief valves. Overpressurization and rupture of the low pressure systems would result in a
loss of coolant accident outside of the primary containment.
The pressure isolation valves were classified properly in the IST program as Category A/C
valves, and leakage rates were tested at least once every refueling interval in accordance
with procedure SP 3601F.4, Reactor Coolant System Pressure Isolation Test, and results
were trended in accordance with Article IWV 3427(b) of the Code. For applied pressure
less than the maximum functional differential pressure (2250 +/- 20 psla), the measured
leakage rate was adjusted by the square root of the ratio between the maximum functional
differential pressure and the test differential pressure. This method comported with the
requirement of Article IWV-3423(e). The inspector found a minor discrepancy in the
,
licensee's calculation in that test pressures measured in pounds per square inch gage were
not correct < d to absolute pressure. Since the error resulted in slightly overestimating
valve leakage rates, no adverse safety consequences ensued.
Manual Valves
The Code requires IST of Category B manual valves that fall within the scope of 10 CFR
50.55a. The inspector noted that there were very few manual valves included in the
Millstone 3 IST program. For example, chemical addition isolation valves 3CCP'V303,
'V304, 'V349, and 'V350 that provide safety class boundary isolation for the reactor
plant component cooling water system were not included in the program or exercised
periodically in accordance with Article IWV-3412 or Section 4.2.1 of OM-10. Per operating
procedure CP-38071, the normally shut valves are opened and left unattended for
approximately 30 minutes when adding chemicals to the system. The licensee explained
the exclusion by citing Section 2.4.2 of NUREG 1482, which states that valves need not
be considered " active" (requiring periodic exercise testing) if they are only temporarily
removed from their safety positions for a short period of time under administrative controls.
The inspector agreed with the licensee's position regarding these valves. However, the
licensee will need to include these, and similar valves, in its IST program as " passive"
Category B valves, as applicable.
c. Conclusions
Power-operated valve exercise tests met or exceeded Code requirements, and the
licensee's use of the motor power monitor diagnostic system was commendable.
'
Nonintrusive testing of check valves also was noteworthy, but more documentation was
needed to meet GL 89-04 requirements. Additional manual valves may need to be added
_ _ _ _ _ _ - - - _ _ - _ _ _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ - -
.
41
to the IST program, even if their safety functions are only passive. Pressure isolation
valves were leakage rate tested in accordance with the Millstone Unit 3 TS and the Code.
U3 M4 Maintenance Staff Knowledge and Performance
M4.1 (Ocen) eel 245/97-202-06. 336/97 202-06.423/97 202-06: Ineffeeliya
MainteAance and Technical Trainino Proaram Evaluation
a. insoection Scoce (41500)
The programs reviewed were non-licensed operator; electrical maintenance personnel;
mechanical maintenance personnel; instrument and control technician; chemistry
technician; radiation protection technician; and engineering support personnel.
10 CFR 50.120 requires that training programs be established, implemented, and
maintained using a systems approach to training (SAT) as defined in 10 CFR 55.4. A SAT-
based program requires 1) Systematic analysis of the jobs to be performed, 2) Learning
objectives derived from the analysis which describe desired performance after training, 3) .
Training design and implementation based on the loaming objectives, 4) Evaluation of
l trainee mastery of the objectives during training, and 5) Evaluation and revision of the
l training based on the performance of trained personnelin the job setting.
The inspectors evaluated 18 of 25 characteristics of a SAT as described in NUREG 1220.
The evaluation involved assessing the SAT characteristics related to systematic analysis of
training requirements, training program design and implementation, trainee evaluation, and
training program evaluation. Unless specifically noted otherwise, the results obtained apply
to each of the training programs reviewed.
b. Observations and findings
An assessment of the programs and processes related to the systematic analysis of the
jobs to be performed indicated the tasks were selected for continuing training based
primarily on the workers' and supervisors' desires to expand their knowledge into new
technical areas. Although appropriate for increasing the level of technical knowledge, this
method would not ensure that on the-job performance was maintained at the level needed
to support safe day-to-day plant operations. Changes to equipment and procedures were
assessed by the licensee to determine their impact on training. Personnel interviewed felt
that changes identified from these assessments were incorporated into training. However,
reorganization of workers and changes in their responsibilities when transferring from the
Connecticut Yankee site were not assessed to ensure that personnel had the appropriate
Millstone site-specific knowledge. Overall, the systematic analysis of the jobs to be
performed was functioning adequately but with weaknesses.
Interview results suggested that workers felt the training they had received was of good
quality. The inspectors observed effective interaction between students and instructor,
and good use of visual aids and job aids during classroom training sessions. The lesson
materials were of good quality and the trainees indicated that the instructor presentations
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42
.
were generally good. However, many of the plant personnelinterviewed indicated that
instructors needed to spend more time in the plant to improve their credibility by obtaining
first-hand knowledge of the uses of the training they were providing. Overall, training
design and implementation was functioning well.
Information gathered in interviews suggested that the evaluation of trainees during training
had weaknesses. Non-licensed operators noted that the examinations they were given
were not a good assessment of the information they received in training and, in at least
one case, were given several months after completion of the training. Additionally,
methods used to remediate non-licensed operators, primarily self study of the lesson plans,
were not sufficient to prevent repeat f ailures, in all reviewed programs, the task selection
process and training methods used in continuing training do not ensure maintenance of task
proficiency. The use of 'significant notices', while timely, does not require any evaluation
to determine the extent to which the information was understood by the workers or to
ensure that newly hired workers will receive the information as part of their initial training.
Interview results also indicated that most people believe the on the-job training and
evaluation (OJT/E) programs should be changed due to known weaknesses. Those
interviewed indicated that the OJT/E process was not formal enough and is not high on the
'
list of management priorities. Additionally, the lack of management emphasis on OJT/E
has resulted in workers not being fully knowledgeable about the status of their own
qualifications, in the maintenance and technical training programs some task qualifications
do not expire and others require periodic renewal, i.e., renewal every year, every two
years, or every five years. However, those tasks that require periodic renewal do not
always require that task proficiency be demonstrated but rather use the opinion of the
supervisor as the basis for continued qualification / renewal of qualification without
consideration of individual task assessment. The weaknesses in the implementation of the
OJT/E process is offset, at least in part, by the apparent willingness of workers to ask for
assistance in task performance or to inform their supervisor if they feel unable to perform a
task even if they are fully qualified to perform the task. Overall, the evaluation of trainee
mastery of objectives during training was inadequate.
The task qualification matrix for engineering support personnel is the notable exception
related to task qualification status. Extensive revisions to the engineering qualification
standards has been undertaken to ensure that qualifications are consistent across all
engineering disciplines. The update to the matrix is viewed as positive by engineers and
their supervisors.
In the area of program evaluation, interview results indicated that although trainee critiques
of training are encouraged and are collected they are not being used to identify potential
deficiencies in the training program. There is also no program to gather job incumbent
performance data related to degraded task abilities, on-the-job experiences, and input from
supervisors regarding performance-based training needs.
The licensee has a number of curriculum advisory committees (CACs) that are specifically
designed to provide site-wide oversight of each of the technical training programs.
However, interview results indicated that the site-wide perspective is frequently lost by
- _ - _ - -
43
holding one-on-one meetings between a training representative and a plant supervisor.
Their discussions, although focused on unit specific issues, may have unexplored site wide
implications that are not being addressed as part of the program effectiveness evaluation.
The notable exception is the health physics technical advisory counsel (TAC). The TAC is
comprised of technician representatives from each unit that meet regularly with the specific
task of discussing task proficiency issues, in general, technical training program evaluation
was found to function inadequately.
The significance of the training program deficiencies identified by the inspectors were I
evalubted against the problems previously identified in the Nuclear Training Department
" Top Ten" List. The " Top Ten" list was developed as part of a corrective action plan
addressing recent problems in the operator training program. However, the inspectors
found that implementing the appropriate corrective actions for each of the eleven items on
the list would not prevent recurrence of the those specific problems nor prevent similar
problems from developing in other training areas because none of the items specifically
addressed the SAT process weaknesses underlying each of the issues.
Although the inspection focused on Unit 3 training programs, the SAT processes are
common to all units at the site. Therefore, the problem g are considered also applicable to
Units 1 and 2. The failure to maintain training programs derived from a systems approach
to training, as described in 10 CFR 55.4 was evidenced by the failure to evaluate trainee
mastery and conduct effective training program evaluation and is considered an apparent
violation of 10 CFR 50.120. (eel 50 245/97 202-06; 50 336/97 202-06; 50-423/97 202-
06).
c. Conclusion:
The overallimplementation of the systematic approach to training (SAT) for the technical
training programs at the Millstone site was generally inadequate to ensure continued
qualification of technical and non-licensed personnel to successfully perform in plant work.
As described above, one violation was identified concerning a failure to properly evaluate
trainee mastery of tasks and conduct training program effectiveness evaluations.
U3 M8 Miscellaneous Maintenance issues
M 8.1 (Closed) Unresolved item 50-423/96-08-18: Adequacy of the IST Program
The results of the licensee's assessment of the Millstone Unit 3 IST program, the corrective
actions planned and implemented, and NRC findings are discussed in Sections U3.M1 and
U3.M3 of this inspection report. An additional NRC concern documented by this item
involved the licensee's failure to perform timely operability determinations for the
components for which IST had not been performed. To correct this condition, the licensee
revised the IST program manual to require a condition report to be initiated if a component
is determined to be within the scope of the Code. The condition report will require that an
operability determination be performed. The inspector concluded that the licensee's
corrective actions addressed the IST program deficiencies.
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44
Additionally, the inspector reviewed the licensee's disposition and corrective action for CR
M3 97 0866 which documented the identification of valves inappropriately left out of the
IST prot, am. Programmatic corrective measures, already in progress, appeared to be
.
adequately directed to the resolution of the documented concerns.
M8.2 (Closed) LER 50-423/96 50:
This LER documented that the range of control building chilled water pump suction
pressure gages used for surveillance were not in accordance with ASME Section XI
requirements. On December 11,1996, the licensee identified that the control building
chilled water pump suction pressure gages did not meet the requirement of Section
5.4.1.2(a) of OM 6 that the full scale range of each analog instrument shall not exceed
three times the reference value. The licensee concluded that pump operability was not
impaired since the gages' full scale range only exceeded the Code requirement by 4 psig,
but otherwise met Code accuracy requirements. The inspector agreed with the licensee's
assessment. The licensee substituted the gages with process computer points that met
the range and accuracy requirements of the Code for digitalinstruments.
The licensee performed a review of other instruments used for IST and documented the
results in memorandum CBM 97-114, dated March 24,1997. Gages and computer points
utilized during testing of pumps in seven other systems, including component cooling
water, auxiliary feedwater, intermediate head safety injection, quench spray, and
recirculation spray, also were found not to conform to OM 6 requirements. As corrective
action, the licensee changed procedures to use substitute gages, changed the calibrated
ranges of the computer points, replaced instruments, and/or revised pump reference flow
rates. At the time of the inspection, many of the substitutions and recalibrations had been
performed, and a design change request to implement other corrective actions had been
developed and was being reviewed.
The licensee determined that the condition was caused by the informality of the IST
program and lack of provisions for periodic assessment of program compliance with the
Code. To prevent recurrence, a comprehensive administrative program document was
written and approved. The guidance contained in the program document comported with
Code requirements, and the new program contained provisions for periodic program
assessments.
The inspector found that the condition would not reasonably have been expected to have
been prevented by corrective actions for previous violations or findings, and the licensee's
corrective actions and actions to prevent recurrence were comprehensive and acceptable.
This licensee identified and corrected violation of the instrument range requirements of OM-
6 is being treated as a Non Cited violation, consistent with Section Vll.B.1 of the NRC
M8.3 (Closed) LER 50-423/97-22:
This LER documented that testing of the control room emergency air filtration system had
not been performed after routine filter replacement in violation of technical specification
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45
(TS) surveillance requirement 4.7.7(f). Two historicalinstances were identified, one in
each train. Each filter train was subsequently tested satisfactorily during normal
surveillance testing. The licensee attributed these events to a lack of a prompting I
mechanism within the applicable maintenance procedures or work orders. Missed TS
surveillances were previously cited as a violation at Unit 3. As part of the corrective
actions for that violation, the licensee will review surveillance procedures to ensure
prompts exist for conditional surveillances. The corrective action is scheduled to be !
completed by September 30,1997.
The inspector reviewed the work orders and maintenance procedures and noted that they
had incorporated the TS surveillance requirement. A'dditional corrective actions are being
performed as part of the previously cited violation. Based on the above corrective actions
and the low safety significance of the issues, this IMensee-ideatified and corrected violation
is being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy. This LER is closed.
M8.4 (Closed) ACR M3-940159 (Partial SIL ltem 151
l
l a. Insoection Scoco (92902)
The inspector reviewed the corrective actions taken by the licensee to resolve the issue
, docurnented in ACR M3 96-0159, the associated purchase order and design calculations
1
for the needed replacement component, and the component design drawings,
b. Observations and Findinas
Letdown heat exchanger 3CHS*E2 had exhibited leakage at the lower flange for a long
period of time. The leaking fluid caused corrosion of the carbon steel flange bolts and
represented a constant source of contamination. The licensee considered corrective
actions to address the leak as early as 1989, as documented in Nonconformance Report
(NCR) 389 239 (dated 7/12/89). However, due to unexpected difficulties, alternate
correction approaches and changing circumstances, the final resolution was still pending in
1996. The proposed corrective action, at that time, was replacement of 21 of the 28
flange bolts with corrosion resistant stainless steel bolts. The design adequacy of the
bolted joint, using only 21 bolts, was based on the use of the new bolts' certified material
tensile properties, inspector review of this proposed corrective action concluded that the
design represented an apparent conflict with ASME code requirements.
The licensee documented this discrepancy in Adverse Condition Report (ACR) M3 96-0159.
The corrective actions to resolve the ACR include replacement of the heat exchanger and
the training of design engineers on code requirements.
The licensee had an available heat exchanger that was essentially identical to the original
leaking unit. To improve the leak tightness integrity and performance characteristics of this
replacement, the unit was returned to the original manufacturer, Holtec International, for
modification, code qualification and testing. The inspector reviewed the vendor prepared
design drawings and code qualification calculations and the licensee's vendor surveillance
_ _ _ _ _ _ _ _ _ _ - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
,
46
.
records for the replacement unit, it was noted that the licensee will provide the necessary
documentation to satisfy the ASME Code Data Report and the ASME Code Reconciliation
during the close out of maintenance modification (MMOD) M3 97512, after successful
acceptance testing at operating temperature and pressure, it was also noted that the
Holtec drawings listed the flange bolt torque as 250 ft lbs instead of the 350 ft-Ibs found
to be necessary to achieve leak tightness during the hydro test. Following the document
review, the heat exchanger was inspected in the field by the inspector, and it was verified
that a refurbishment plate was installed and correctly stated the new shell design pressure
of 165 psig.
The inspector discussed the purchase and installation effort with the responsible licensee
project engineer. The engineer provided documents to show that the paperwork to achieve
ASME Code compliance was in place and confirmed that a design change notbe (DCN) to
revise the flange torque values to 350 ft-Ibs on the component drawing had been issued.
To assess the corrective action regarding training, the inspector reviewed the lesson plan
and interviewed several engineers who had received the training. Most of the interviewed
engineers were responsible for stress computations and had a clear understanding of the
issue and correct design procedures for bolting. The lesson plan was concise,
c. Conclusions
Replacement of the 3CHS*E2 heat exchanger resolved the flange leakage problem. With a
new, larger sealing gasket, it could be a permanent solution. Interviews with design
engineers confirmed their understanding of ASME Code requirements for flange bolting.
The inspector concluded that the licensee's corrective actions were appropriate and ACR
M3-96-0159 is considered closed. The NRC will review, as inspector follow up item (IFl
50-423/97 202-07), the results of the heat exchanger performance tests and the
associated completion of documentation to show ASME Code compliance when the plant
achieves normal operating temperature and pressure.
M8.5 (Closed) ACR M3-96-0563 (Partial Sll item 33)
a. Insoection Scoce (92902)
The inspector reviewed the corrective actions taken by the licensee to resolve the issue
documented in ACR M3-96-0563 regarding the access manholes to the Normal and
Reserve Station Service Transformer fire protection water valve pits,
b. Observation and Findinas
Manholes provide acce s to the Normal and Reserve Station Service Transformer fire
protection water valve pits. Several Adverse Condition Reports (ACR's) were issued to
request relief from the inspection and surveillance burdens associated with making access
to the pits. When the access manholes are covered, the pit air spaces must be sampled
before entry. When the manholes are left open, only a daily sampling is required but the
openings present a fall hazard which must be protecteo against. To accommodate frequent
_ ____ - ___ - - ---
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. 47
access, the manholes had been lef t open and temporary guards had been installed.
However, due to their temporary nature, the guards required constant surveillance. The
deficiency of the temporary guard and the burden of frequent sampling was noted in
several ACR's. To resolve this concern, permanent protective guard rails were insta'ind at
the two manholes. They were designed to meet OSHA strength and dimensional
requirements and to accommodate ready access.
-
1
An inspection of the Normal and Reserve Station Service Transformer fire protection water
valve pit access manholes was made by the inspector. Stainless steel tallings, bolted to i
the concrete pads and walls, with drop chains at the entry points, were installed at each I
manhole. The inspector discussed the ACRs with their originator who was satisfied that
the railings resolved his concern. When queriod why there were multiple ACRs for the
same issue, he stated that there were some initial misunderstandings of his concern,
c. Conclusio_nB
The permanent railings at the Normal and Reserve Station Service Transformer fire
protection water valve pit access manholes appeared structurally sound and met OSHA
dimensional and design requirements. The inspector concluded they were an appropriate
resolution of the reported concern. Based on their installation, ACR M3 96 0503 is
considered closed.
1)).lli Engineering
U3 E2 Engineering Support of Facilities and Equ;pment
E2.1 [Uodato - Slklitm 57) ACR M3 96-0080: Inadeouste Seoaration BetvitpD
Redundant Electrical Circuits, and ACR M3 96-0081: Potential Electrical Seoaration
Violations with Solid State Protection System
e, insoection Scoop (92903)
ACR M3 96 0080 identified potential noncompliances with electrical separation
requirements for the reactor trip switch on Main Control Room (MCR) Board MB4 (MCB-
MB4), and the safety injection switches on MCB MB2 and MCB MB4. These conditions
have existed since unit startup in 1985. A root cause of the elecPical separation
noncompliances was identified as inadequate job skills for maintaining electrical separation
during maintenance and modifications.
ACR M3 96-0081 identified potential electrical separation violations associated with
electrical wire bundles for the two trains of the Solid State Protection System (SSPS). The
power cable supplying power to the opposite SSPS train:, was less than one inch from the
internal backplane wiring in the logic cabinets.
The inspector reviewed the licensee's corrective actions to address the above concerns.
.
48 .
b. Observations and Findlys
Following the discovery of the noncompliance with electrical separation requirements for
redundant protection equipment trains on June 10,1996, the licensee staff performed
additional system walkdowns to sarch for discrepancies in electrical separations of: (i)
installed wiring in other MCR Panel Boards, and (ii) electric cables on cable trays in various
)
plant areas. These additionalinspections identified numerous electrical separation 1
noncompliances on various MCR panel boards and electrical cable installations in general
plant and protected areas. (Reference LERs 96 015 01 and 96-015 02). The licensee's
corrective actions were: (il modifications to install electrical separation barriers and *re- )
train" cables as necessary, i.e., redundant cable trains tie wrapped to minimum separation
distancet, (ii) develop training module on electrical separation and implement continuing l
training for applicable personnel, and (iii) revise applicable work planning process i
'
procedures to incorporate guidance for electrical separation inspection plan development.
l
Separation barriers made of QA 18 gauge galvanized sheet metal have been installed on
the inside of the MCR panel boards MB4 and VP1 to correct the discrepant conditions.
Based on field walkdowns of the MCR panel boards, the inspector verified that the installed
'
barriers were in compliance with Ron. Guide 1.75 and IEEE Std. 384 1974 requirements.
. The barriers were found to be securely mounted on the panel boards with no air gaps
observed. The Control Building Isolation pushbutton (PB13HVC CB1) located on
3HVS'PNLVP1 has been returned to service after successful functional retest results per
surveillance procedure SP 3614F.3.
On the insides of several MCR panel boards identified on the Unit 3 electrical separation
discrepancy list, electrical wire bundles have been tie wrapped to maintain acceptable
separation distances. The licensee's OC inspection results for AWO M3 97 03509
indicated that the completed re training of electrical wire bundles on the internal MCR
panelboards, MB1 to MB6 and VP1, met the acceptance criteria for electrical separation.
Based on field walkdown of the affected MCR panel boards, the inspector aid not find any
operabluty concerns.
LER 96-015 02 (an update of LER 96 015-00 and LER 96-015 01) identified electrical
separation noncompliances in specific areas of the MCR panel boards. Interviews with the
licensee staff indicated that work is in progress to correct the identified noncompliances.
The inspector also conciucted field walkdowns in other plant areas, e.g., cable spreading
room, diesel generator room *A", and electrical switchgear room "A", to assess whether
cable arrangements are in compliance whh separation requirements. The inspector did not
find any new noncompliances which were not identified by the licensee's electrical
separation inspection program. LER 96 049 01 has identified 976 deviations of minimum
separation distances between a Class 1E and a non-Class 1E cable in the cable spreading
and instrument rack rooms. The licensee indicated that about 160 noncompliance items
have been corrected through re training of the cables, and repair of Sil temp protective
wraps. Another 540 noncompliance items are related to inadequate separate distances
between cable trays. The licensee is in the process of issuing DCNs for the installation of
cable wraps to meet the regulatory requirements. However, the proposed modifications are
not fully implemented yet. Since the work on correcting electrical separation
_ _ _ .
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49
noncompliances is ongoing and expected to be completed prior to plant startup, this issue
will remain open.
One corrective action for ACRs M3 96 0080 and M3 96 0081 is the adequate training of ,
applicab!c personnelin the Engineering Department and General Technical Services who are
responsible f or neaintaining electrical separation requirements. A training program on
electrical separation requirements was developed. Classroom treining on separation criteria
for electrical wiring in electrical panels and cabinets, and for cables and raceways in
general plant areas and cable spreading areas were provided to applicable personnel from
l November,1990 through April,1997. The inspector found that the training course
contents (in ES CONT C098) adequately identified the regulatory requirements and * thumb
rules" for electrical separation to the students. However, minor comments on the exact
definitions of technical terms (e.g., common cause initiating events) were provided to the
licensee training staff to enhance the training course materials. The licensee agreed to
incorporate these comments in the classroom training materials.
l The Millstone Station Procedures U3 WC1, " Unit 3 Work Management," and U3 WP2,
" Unit 3 Work Planning," have been revised to include guidance for development of
electrical separation inspection plans when electrical maintenance on safety related or non-
safety related cables, conduits, or raceways are required. These procedural revisions were
effective as of June 1,1997.
c. Conclusions
The licensee has developed a training program on electrical separation requirements, and
classroom training has been provided to applicable personnelin the Engineering Department
and General Technical Services. The licensee has also completed revisions to work
planning procedures to include guidance for development of electrical separation inspection
plans. However, work on correcting electrical separation noncompliances in the MCR panel
boards and other plant areas are ongoing to meet the plant startup deadline For example,
installation of separation barriers in other MCR panel boards hav:; not been completed.
Since corrective activities are ongoing, this issue will remain open.
U3 E3 Engineering Procedures and Documentation
E3.1 Site level MEPL Proaram Review
The overall site material, equipment, and parts lists (MEPL) program was reviewed;
comments and discussion that apply to all three units are provided here.
The inspector reviewed the following MEPL related documents:
. NGP 6.01 Material, Equipmen;, and Parts Lists for in-Service Nuclear Generation
Facilities, Rev.'9, 8/13/94.
.
NGP 6.05 Processing and Control of Purchased Material, Equipment, Parts, and
Services, Rev. 8.
_
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l
50
Program), Rev. O,7/12/95 through Rev. 4, 4/20/97.
- Production Maintenance Mana0ement System (PMMS) Training Manual.
+ PMMS User's Guido Volumes 1 & 2.
- PI 29, Development of Millstone Unit 3 Design Bases Summary Documents, Rev.1,
Effective date 3/11/97.
- Northeast Utilities Quality Assurance Program (NUQAP) Topical Report, Appendix A,
Rev.18, 8/15/95.
- Engineering Self Assessment of the Material, Equipment, and Parts List (MEPL)
Program, Millstone Unit No. 3, ESAR PES 97 009,4/12/97.
- Selected MEPL evaluations, and MEPL related ACRs and CRs.
- NGP 0.10, Use of the PMMS ID. System and BOM Database, Rev. 8.
At the time of tl. iinitial MEPL Program difficulties (discussed under MEPL Program status),
the controlling document was NGP 0.01. This has subsequently been replaced by the
improved Specification 944. Specification 944 has also undergone improvements and
revision over the last two years. The new Specification provides detailed guidance for the
MEPL process in Figures 7.3 and 7.4, which are used to document the evaluations and
subsequent reviews. The Spec. addresses both component level MEPL evaluations and
l parts Bill of Materials (BOM) MEPLs. Section 5 provides instructions on the safety
l classification process, in particular: determination of the licensing basis and the safety
function at the plant, system, component, and part level, it covers safety related,
augmented quality, and non-safety-related determinations. Figures 7.3 and 7.4 provide for
a safety evaluation and USQ determination for changes in classification. The licensee has
l
also established added controls over any changes to the system where the parts
classification information resides (namely, NGP 6.10 to control the PMMS System).
The MEPL program is now receiving significant resources and attention at the site level and
in Units 2 and 3. Unit 1 ef forts will begin in earnest when the work on Unit 3 is
completed. Four issues were identified with respect to the site level program, as follows:
1. There continues to be a historical question of the potential to have non safety-
related (NSR) parts installed in safety related (SR) components. This has been
I documented on a number of ACRs and CRs for each unit. The plans to address this
l concern for U3 appear comprehensive (but are not fully implemented yet). For U1
! and U2, the plans are currently less comprehensive and implementation is not as f ar
along. The licensee has not yet fully justified the plans for Units 2 & 3.
2. Specification 944 does not check for the impact on NUQAP, Appendix A when
downgrading a component from SR to NSR. Any changes to the NUQAP that
_ _ .
. . - . . . . - . , .
.
.
51
reduce commitments (e 0., the list of SR items) require prior NRC approval per 10
CFR 50.54(a).
3. NRC previously (Inspection Reports 95 07 and 95 09) raised a concern that the
MEPL procedures did not adequately consider normal operations and anticipated
operational occurrences (AOOs) as part of the " design basis events" to be
considered when making safety related classifications under the MEPL program.
Discussions with NU managers responsible for the MEPL program stated that the
intent of the current program, under Spec. 944,is that engineers performing MEPL
evaluations must consider normal operations and AOOs as part of the * design basis
events"in making safety related classifications. Step 5.2.2.4 of Spec. 944 states
that guidance can be found in EPRI NP 6895. Page 4 2 of NP 6895 contains a
definition of Design Basis Events that includes normal operations and AOOs, as well
as other items. This indirectly addresses the concern, however personnel
performing evaluations will not usually have or reference the EPRI document.
4. The PMMS database is not complete. Some SR components are not in the
database, e.g., snubbers. Many augmented QA and NSR parts and components are
also not in the database. The impact on site programs of these gaps in the
database needs to be evaluated.
E3.2 (Uodate PartiaLSLLite_m 25) ACR M3 96 0912: Acoarent Violations and Escalated
EQtomement items from NRC Insoection Reoort 96 201. Items No. 18.19. & 43
This ACR addresses three apparent violations from NRC inspection report 90 201. These
items are also under consideration for escalated enforcement action, which has not been
completed yet. The items relate to the MEPL program, which is reviewed in this section of
the report. Issues associated with the MEPL program are identified herein. The licensee is
still actively working on MEPL evaluations that must be completed before startup. Also,
there are other areas of inspection review on the program that will be performed over the
next reporting period. SIL ltem 25 remains open.
E3.3 Unit 3 MEPL Status Uodate
Unit 3 has approximately 60,000 components in the PMMS database, of which about 19K
are safety related (SR) and 3,000 are augmented quality (due to fire protection, radwaste,
station blackout, or ATWS commitments). During the Performance Enhancement Program
(PEP) reviews a number of components were originally identified for downgrade, however
this action was stopped in Unit 3 before being implemented as a result of lessons loamed
on Units 1 and 2. Over the 1995 and 1996 time frame Unit 3 performed system level
MEPL evaluations of all systems and hence all components in the database. As a result of
these efforts a number of changes in component classification were implemented, and are
generally summarized here:
- About 3,000 duplicate items were identified and removed from the database.
- About 2,000 items were downgraded from eugmented quality to NSR.
- About 1,000 items were upgraded from NSR to augmented quality.
_ _ - - - - -
,
.
52
,
- About a dozen items were upgraded from NSR to SR, but did not require physical
changes to the components.
- About another dozen items were identified where NSR components had to be
upgraded to SR, but these items required design modifications to change out
equipment. These modifications are stillin progress.
- About 2,000 to 3,000 items were down0raded from SR to NSR. These items were
all either database errors or downgrades of items that had been classified as SR due
to utility convenience rather than regulatory requirements.
The above activities were all at the component level. For each component, the MEPL
prcgram also evaluates the parts of the components and establishes the classification for
each part on the Bill of Materials (BOM). In early 1997, Unit 3 performed an operability
determination (OD No: MP 010 971 that satisf actorily evaluated all safe shutdown, SR
components with one or more NSR parts in their BOM. This included an engineering
evaluation, " Acceptability of Installed Parts / Material Associated with Active Components
Credited for Defense in Depth." In 1996 and 1997 Unit 3 began MEPL BOM avaluations
for all SR components that have ever had any work performed on them. As part of this
effort, whenever NSR or Undetermined (U) parts are reclassified to SR, a full work history
examination is being performed to ensure acceptable quality of parts installed the
components.
E 3.4 UDL13 MEPL Proaram imolementation (Uodate Partialjlkitem 25)
The 6.:spector selected a system MEPL evaluation (for the CVCS S) stem) and a few
indivioual component MEPLs for review to determino if classification determinations were
reasonable and properly documented. The MEPLs were compared with drawings, FSAR
descriotions, and components in the plant. Additionally, a number of components and
compoi ent identification were noted in the plant and compared to the MEPL and PMMS
systems to ensure that the components were properly classified and were properly entered
into PMMS. The parts issuance portion of the program was not reviewed due to ongoing
issues identified by the licensee in that area.
The inspector noted the following five issues, which will be tracked with SIL item 25.
1, in order to properly classify an item in the MEPL Program, the safety function must
be clearly understood. The latest revision of Spec 944 requires this to be
determined and documented in the MEPL evaluation. The earlier versions of the
Spec. also recognized the importance of determination of safety function, but were
not as specific in the procedure. The MEPL evaluations reviewed did not always
clearly document all of the safety functions Examples include: the overall CVCS
System, the CVCS function with respect to the Reactor Coolant Pump seals, and
valves CHS * V501, 'V505, 'V436, 'V437, AND 'V303.
2. The MEPL evaluations reviewed did not list all of the pertinent design documents
and FSAR references on the MEPL determination, Figures 7,3 or 7,4 (example,
identify CVCS System MEPL).
)
l
__
s
,
53
3. The numbering scheme for PMMS results in differences between the identity for
components in the field and in the PMMS database when the number of characters
exceeds 15.
4. FSAR Figure 3.2.2 states that an asterisk (') indicates that equipment is quality
assurance category 1 (i.e., SR). However, the inspector noted that not all SR
components use the * as noted in the FSAR, e.g., SR snubbers; there is some j
ambiguity in the use of the ' for relays; and some identification tags and signs in
plant do not use the *, even though the component is SR and the * is used in
PMMS,
5. - While performing the MEPL related plant tours, the inspector noted that some
orango or A Train components are being newly painted purple (the color of the B
train), e.g., OSS pump and AFW pump. This creates an increased potential for
" wrong train" type of human errors.
E3.5 (Undatel Unresolved item 50 423/95 07 10: Containment Hatch Downaradina SR
eauloment throuah the MEPL orocram
Through the early 1990s, NU had a program to review, and where possible, downgrade
components from safety related to non safety related. This item addressed the issue of
improper downgrades. The generic or programmatic aspects of the downgrades are being
addressed under the Eels and SIL 25 noted herein. One particular component identified
with this unresolved item was the containment personnel hatch and its interlocking system.
MEPL Evaluation No. MP-CD 132 downgraded a number of parts associated with the
containment batch. As a result of concerns raised, the licensee re evaluated the pressure
retaining parts of the hatch and raised their classification from NSR to SR. This action then
required a design change (PDCR MP 95 025) that was implemented to upgrade these parts
to SR. 'There are currentiv 231 parts on the hatch BOM. Over the last two years, a
number of MEPL evaluations have been performed on the containment hatch parts. One
particular aspect in question was whether the hatch interlock mechanism served a SR
function. The MEPLs determined that it did not; and, the inspector verified this by a review
of the design drawings and discussions with the pertinent engineers. During this review-
the inspector noted the following issues:
1. - The most recent MEPL (CD-789) for the hatch did not clearly specify which of the
previous MEPLs had been superseded and thus it was not clear which of the
multiple MEPLs were still effective.
2. The PMMS system incorrectly notes that CD 789 is the pertinent MEPL for all
containment batch BOM parts in PMMS.
3. The acceptance criteria (on Maint. Form 3712X+1, Rev. 2) for the Technical
,
Specification surveillance test do not accurately verify that the hatch interlocks
function properly. However, the steps and the note within the procedure itself (SP
3712X, Rev. 5) do properly test the interlocks.
_ ___-___ __ - _
.
54 .
This unresolved item remains open pending resolution of the above notad issues.
E3.6 RHR System Control Valves
As an example of a SR component with associated NSR parts and components, the
inspector selected the residual heat removal (RHR) system flow control valves for the RHR
heat exchanger (HX). 3RHS*HCV606 &G07 (HX outlet valves), and 3RHS'FCV618 & 619
(HX bypass yalvest. These valves were identified in ACR 13427 on 6/15/96, as having a
design problem whereby their f ailure position on loss of control air would give maximum
cooling. This is apprcpriate for the RHR system but could cause an over temperature
condition in the reactor plant component cooling water system (CCP). This resulted in a
l MEPL evaluation MP3 CD 0947. This design change makes several modifications,
including: limiting the full open position of the HX outlet valves, failing open the RHR HX
bypass valves on loss of air, and adding a SR solenoid valve between the valve positioners
and the actuators to ensure a vent path to place the control valves in their safety position
when required. The inspector reviewed the associated documentation and observed the
modification work in progress in the plant. The MEPL evaluation appropriately classified
the various items in accordance with the new design.
.
During the review of these valves, the broader question of SRINSR Interactions (particularly
l as it concerns interactions between control grade and SR components) was raised. The
f licensee presented an Engineering Report M3 ERP 97 0008, Rev. O, dated 6/19/97, titled
" Assessment of Safety Related Valves with Nonsafety Related Controls." This report
'
analyzes 101 valves and associated controls in Unit 3. This is a comprehensive study
which establishes design criteria and groups, analyzes each of the valves, and recommends
changes where needed. In general the analysis of the control grade components assumes
f ailure in the adverse direction if it may be in a harsh environment (such as post LOCA or
HELB). If in a mild environment, the analysis is performed for two cases, with the control
grade components operating as designed and with them failed "as is." Random or spurious
failures of these components may be an initiating event, but are not assumed to occur
concurrent with a design basis accident. This position was verified to be consistent with
NRC review positions noted in: the Standard Review Plan (SRP), NUREG-0800, Section
7.7; Resolution of USl A47, Generic letter 8919, and NUREG 1217; and issues
surrounding Information Notice 79 22.
No unresolved issues were identified as part of this review.
U3.E7 Quality Assurance in Engineering Activities
E7.1 Review of items to be Comoleted Af ter Restart
a. Insoection Scoce 192903)
In a letter dated April 16,1997, the NRC superseded the " Demand for Information" of
earlier letters and requested that the licensee provide, in part, the following information
pursuant to 10 CFR 50.54(f):
- _ _ _ _ - _ _
. _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _- ___ _ - _ ____
55
e For each unit, the list of significant items that are needed to be accomplished prior
to restart;
e For each unit, the list of items to be deferred until af ter restart; and,
e For each unit, the process and rationale used to defer items until af ter restart.
The letter also requested updates approximately every 45 days for the fi;;t two items. On
May 29,1997, the licensco provided the initiallists for Units 2 and 3 in responto to this
letter. On July 14,1997, the licensee provided'the initlat lists for Unit 1 and updates for
Units 2 and 3.
The inspectors reviewed the information provided for Unit 3 to assess the content of the
list and whether the deferrals were appropriate. Specifically, the inspectors reviewed a
sample of deferred items to ensure issues that could affect equipment operability or the
ability of equipment to perform its intended design basis function were not deferred. The
inspectors also reviewed the licensee's process for identification of significant items for
restart and items which could be deferred.
b. Observations and Findinas
Sianificant item For Ru$ tart List
To develop the significant items for restart list the licensee reviewed all adverse condition
reports (ACRs) open as of January 1,1996, and all ACRs and condition reports (CRs)
initiated after that date. Significance level A or B ACRs and level 1 CRs were included as
significant items. The lower significance level ACRs/Crs were screened further and those
issues that questioned the operability or design basis function of maintenance rule group 1
or 2 systems were included as significant items, (Maintenance rule group 1 and 2 systems
include safety related systems and risk significant systems.) The licensee noted that there
are also many other non significant items that are planned to be completed prior to plant
restart. The inspectors concluded that the licensee significant items for restart list
provided the information requested in paragraph 1 of the revised 10 CFR 50.54(f) letter
dated April 16,1997.
Def erred items J. int
'
- The licensee provided the screening criteria used to defer items in their May 29,1997,
response letter. Similar criteria are also provided in Project instruction (PI) 20, * Unit 3
Startup item Administrative Instructions." Items screened to determine if they could be
deferred included unresolved item reports (UIRs), non significant ACRs and CRs, non-
conformance reportu (NCRs), engineering work requests (EWRs) and automated work
orders (AWOs). An item was classified as startup required if it was necessary to
accomplish one of the following actions:
e implement or support a change to plant technical specifications,
.
56 ,
e Correct a licensing or design basis deficiency,
e Accomplish a restart license commitment,
I
e Resolve an operability concern associated with a maintenance rule group 1 or 2
system.
If the item did not fit any of these categories it was considered for deferral, subject to
management concurrence.
A total of approximately 1500 items were included on the deferred issues list at the time of
the licensee's update on July 14,1997. The inspectors reviewed the one line description
of all of these items and selected approximately 30% for additional review, in selecting the
items for further review the inspectors considered those items in safety significant systems
where the one line description indicated the potential for equipment operability questions or
other operational concerns. The inspectors reviewed supporting documentation for these
items and discussed the issues with the licensee staff as necessary to obtain sufficient
information on each of the items. The inspectors had the following findings:
- Open item reports (OIRs), which document potential testing deficiencies, were not
included in the initial (May 29,1997) submittal of deferred items. However, when
questioned by the NRC, OIRs were included on the deferrallist in the July 14,1997,
update,
o The NRC's April 16,1997, letter specifically requested that bypass jumpers and
control room deficiencies be included in the deferred items list. The licensee did not
originally review these items for inclusion in the list. However, when questioned by
the NRC, the licensee reviewed these items and found that all but one of the bypass
jumpers and control room deficiencies had been included as deferred issues as a
result of another associated document, such as an EWR or AWO The item that
was not included was a recorder associated with a non safety system and would
- not have affected safe operation,
o The licensee's July 14,1997, update added items to the deferred list that existed
well before the time the initial list was submitted, but these items were not included
on either the original deferred list or the significant items for restart lict, it was not
evident to the inspectors or discussed in the update letter whether the initial
screening addressed these items or if they were initially screened as non significant
restart issues,
e The inspectors identified twenty two items on the deferred list that the licensee did
not intend to defer For ten of the items, the individual actions necessary to resolve
the issue were scheduled for completion prior to restart. In nine cases all actions
necessary to close the issue were already complete. The licensee reclassified three
items that were questioned by the inspectors. Two items were AWOs to repair
three emergency lights and were placed on the startup schedule because the
affected lights were included in the 10 CFR Part 50, Appendix R program. The
-. _
-- --
_
.
l. 57
other item that was reclassified to be required for startup was an EWR to replace a
-level recorder in the auxiliary feedwater system.
The inspectors found that the licensee did not have a consistent method for coding
restart actions in the Action item Tracking and Trending System (AITTS). Some
l _ actions were coded to a schedule reference to clearly indicate that the action was
! required to be completed prior to startup. Other items required before restart did
l not have a schedule reference entered and were tied to startup only by having the
requested action completion date precede the expected startup date. The licensee
1
documented this concern on CR M3 97 2265
In addition, the inspectors discussed with the licensee the status of the corrective actions
recommended in self assessments, independent third party reviews, nuclear oversight
reviews, and on site review organization reviews (ie, ACR 7007, Root Cause Evaluation -
Effectiveness of the Oversight Organization, Joint Utilities Management Association _ report,
etc.) and if any were to be deferred. The licensee stated that they are currently reviewing -l
all of these reports and will address what actions they have taken or will be taking in their -i
response to item (4) of the NRC's April 16,1997, letter. Specifically, item (4) requested 1
. the licensee to submit what actions they have taken to ensure that future operation of each
unit will be conducted in accordance with the licensee, regulations, and Final Safety
Analysis Report (FSAR). l
c. Conclusions
The inspectors found that the licensee's determination for which items could be deferred
was generally appropriate. The three items that were removed from the deferred items list
as a result of this inspection would not hr.ve had a significant impact on plant operations if
they had not been resolved prior to startup.
However, the inspectors concluded that the deficiencies discussed above constitute a
violation of paragraph (a) of 10 CFR 50.9 which requires licensees to provide complete and
accurate information. (VIO 50-423/97 202 08)
Also, in resolving CR M3 97 2265 the licensee should ensure adequate controls are in
place to ensure that actions required prior to startup do not get inadvertently dsferred as a
result of changes to action due dates in AITTS. This is particularly important for those
items that have some actions required for startup and other actions that may be deferred.
U3 E8 Miscellmnus Engineering leeues
E8.1 Residual heat Removal (RHR) Heat Exchanaer Boltina Susceotible to Boric Acid
Attack (Sil. Item 47)
a. insoection Scone (92903)
The inspector reviewed the licensee's adverse condition report (ACR) No. M3 96-0391 that
addresses the RHR heat exchanger bolting susceptibly to boric acid attack (SIL ltem 47)
=_
.
4
l 58
.
b. Observations and Findings
, During a 10 CFR 50.54(f) walkdown of the RHR system, the licensee identified that the
i RHR host exchangers have high strength carbon steel (B7) studs installed in the shell/ head
flange and, therefore, may be susceptible to boric acid attack since these flanges have
been leaking. As a part of the ACR's disposition, the licensee performed operability and
reportability determinations. The inspector reviewed the licensee's records with the
following observations discussed below.
To determine the extent of a potential boric acid attack of the studs, the licenses removed
five studs with evidence of boric acid stains. The visualinspection performed on these
studs revealed them to be in good physical condition; the studs exhibited good metal
condition, full thread form and no pitting attack below the minor diameter of the studs, in
addition, the licensee performed a magnetic particle (MT) surface examination of the studs
and did not identify any circumferential flaws on the examined studs. There was no loss in
material that would detrimentally affect the strength of the studs or impact the integrity of
the joint. The structuralintegrity of the A and B RHR heat exchangers was never
compromised. Therefore, the A and B heat exchangers were found operable. This
operability determination was based on the good condition of the removed studs and the
results of the MT performed on the studs. Further, reportability was not required because
degradation of the pressure boundary did not occur, and the plant was not operated outside
the design bases,
c. Conclusion
The inspector concluded that the licensee's actions to address ACR No, M3 96 0391 were
adequato. The licensee's documentation and interviews conducted by the inspector with
the cognizant personnel showed sufficient evidence which demonstrated that the RHR heat
exchangers were operable in their as found condition due to the good condition of the
examined studs. As a preventive action, the licensee will continue to monitor these studs
by removing and examining five bolts every five years. SIL ltem 47 is closed,
E8.2 Unsecured 1 Beam Above Safetv Related Comoonents (SIL ltem 37)
a. Insoection Scone (92903)
The inspector reviewed the actions being taken by the licensee to remove an unsecured
structural member installed above safety-related components and the actions to prevent
future installations of this nature,
b. Obiervations and Findings
During a walkdown of Millstone Unit 3 on March 12,1996, an NRC inspection team found
a temporary l beam installed above three of the four recirculation spray system (RSS) heat
exchangers. The licensee reported this condition to the NRC on March 13,1996, in -
accordance with 10 CFR 50.72, after determining that the I beam had the potential to
render both trains of the RSS inoperable during a seismic event. The licensee initiated ACR
!
I
- - _ = =
- - . _ . - . _ _
.
'. 59
No.10382 to remove the l beam and to perform an engineering review of the historical
impact on plant operations. The inspector walked down the areas and verified that the l-
beam had been removed. An NRC team inspection determined that this l beam removal
was adequate corrective action. However, the team was concerned about the lack of
instructions or procedures to prevent recurrence; documented as eel 423 20121, and part
of SIL ltem 37.
.
In response to this NRC concern, the licensee revised Maintenance and House Keeping
Procedure No. OA8, Revision 0, which emphasized the proper storage, use and restraint of
temporary structures or equipment installed above safety related equipment. The inspector
i reviewed the procedure and found that it adequately addressed the NRC's concern and
l
provided some clear guidelines for the restraint and Installation of temporary structures
above safety related components. 'l
! - c. Conclusion
The inspector concluded that the licensee's corrective action was adequate. In addition, ;
the licensee revised their maintenance and housekeeping procedure to provide engineering
'
and maintenance personnel with a clear guidance for the restraint and installation of
temporary structures above safety related components. Therefore, the technicalissues
involved with this item are closed, and SIL ltem 37 is partially closed. eel 423/96 20121
remains administratively open pending completion of enforcement actions.
E8.3 (Undate) eel 423/96 20124: Concrete Spalling of Service Water (SW) Pump
Pedestal
(Partial Closure) SIL ltem 37: Corrective Action Effectiveness
a. Insoettion Scoce R2103J
The inspector reviewed the licensee's actions taken to resolve the issues documented in
eel 423/96 20124; spalling of SW booster pump,3SWP'3B, concrete pedestal. Spalling
of the pedestal resulted in the pump being declared inoperable since the anchor bolts
holding down the pump did not extend past the pedestalinto the concrete floor; thus the
ability of the pump to withstand a seismic event could not be guaranteed. This condition
had existed for an extended period of time and had not been identified and corrected by the
licensee,
b. Observations and Findinas
As corrective action, the SW booster pump pedestal was repaired and a protective coating
was applied to the pump pedestal. The licensee concluded that the pedestal damage was
caused by condensation entering cracks in the concrete, causing the rebar to rust and
expand Other SW system components were inspected for similar conditions. Walkdowns
revealed that several other pump pedestals were cracked; however, the licensee
determined that none of the cracks affected the seismic capability of the components. The
anchor bolts for these components extended into the concrete floor. To prevent
--
.
60 .
recurrence, the licensee revised procedure EN 31094, " Millstone Unit 3 System Engineer
Walkdowns," to ensure that other equipment foundations are inspected during system
reviews. In addition, procedure EN 31098, 'MP3 Condition Monitoring of Structures," had
been put in place under the Maintenance Rule to monitor safety related structures for
structural degradation.
The inspector reviewed the work orders and design change notices that were issued to
repair the damaged components. Pedestals that were Identified as cracked were repaired
with Five Star Structural Concrete, and a protective coating was applied to the pedestals to
minimize water intrusion into cracks. A review of the m::nuf acturer's instructions revealed
that the concrete used for the repairs had a higher compressive strength than the concrete
used for the original concrete pads, in addition, a walkdown of the auxiliary building
, revealed that all degraded pump pedestals had been repaired or were identified and
l scheduled to be repaired by the licensee,
c. Conclunon
The inspector concluded that the technicalissue resolution and corrective actions for this
particular concern were good. However, the closure of this issue does not address the
'
overall effectiveness of the licensee's corrective action program. Continued inspection of
-the corrective action program will bs reviewed as followup to SIL ltem 37. SIL ltem 37 la
partially closed. eel 96 20124 remains open due to ongoing NRC considerations of
potential escalated enforcement action involving this issue.
E8.4 (Ocen) eel 423/97 202-09: RSS Dosion Deficienev
j (Closed) LER 50-423/97-03, Potential RSS Water Hammer
LER 50-423/9715. Potential RSS Vortexing,
LER 50-423/97 28, Potential Loss of RSS Pump NPSH,
luodatel Sllitem 85 Other RSS and Related Design Basis Concerns
On January 13,1997, a licensee engineering evaluation determined that the recirculation
spray system (RSS) heat exchangers and piping may be susceptible to water column
'
separation, and subsequent water hammer events, if the RSS pumps are restarted during
design basis accident conditions. On February 4,1997, a licensee review of design
calculations identified that the calculated minimum water levelin the containment sump at
the time of the start of the RSS pumps following a large break loss of cooling accident
(LOCA) would be below the containment sump vortex suppression gratings. It was
determined that cavitation of the operating RSS pumps could result from the air
entrainment which would accompany the postulated vortex formatioriin the sump coolant.
On April 10,1997, another review of the design calculations for the not positive suction
head (NPSH) for the RSS pumps identified the potential for steam flashirig and partial
voiding of the coolant from the containment sump based upon suction line head losses in
excess of the calculated availability of saturated coolant head conditions.
. _ _ _ _ _ _ _ . ._ _
---_.-_._--_d
61
l.
All three of these licensee identified design deficiencies were reported to the NRC
(respectively, LERS 97 03, 97 15, & 97 28), within the required time framos delineated in
10 CFR 50.72 and 50.73, as conditions outside the design basis of the plant and,in the
case of the NPSH concern, also as a loss of safety function. The cause for all three events
,
was determined by the licensee to relate to inadequate initial RSS design scope and to
l Inadequate engineering review and process control during plant construction, i.e., prior to
l the issuance of the initiallow power operating license, NPF 44, in November 1985.
I Additionally, the above noted problems with the RSS design relate to a concern
l documented in LER 96-97, as supplemented, involving the RSS piping and supports being
exposed to temperatures in excess of those for 'which stress analysis had been conducted
prior to initial licensing. NRC inspection follow up of this latter concern (i.e., LER 96-07) is
documented in inspection report 50-423/96 06, concluding that the operation of the unit
with the existence of such a design deficiency constitutes an apparent violation (eel
423/96 06 13) of regulatory requirements. The inspection documented in IR 96 06 also
represents an update of Sllitem 1.
In establishing the cause of the event documented in LER 96 07, the licensee determined
that the identified " conditions have existed as part of the original plant design of the RSS
(and other affected) systems." Also, LER 96-07 documents a condition in which the plant
operated outside its design basis, resulting in the inoperability of, along with other analyzed
systems, the RSS. The commonality of cause (initial design errors), effect (unit operation
outside the analyzed design conditions), and specific system impact (RSS inoperability),
that connects LER 96 07 with the other three LERs also supports the conclusion that the
design deficiencies discussed in LERs 97 03,9715, and 97 28 collectively represent an
additional apparent violation (eel 423/97 202 09) of regulatory requirements.
The technical details, corrective measure impicmentation, and design changes intended to
address the problems discussed in these three LERs will be tracked with the apparent
violation, as well as with this Update of SIL ltem 85. Therefore, LERs 97 03,9715, and
97 28 are herewith individually closed.
E8.5 1 Closed) URI 96 20140 (Partial SIL litmll)
a. Insoection Scoce (92903)
The inspector reviewed the engineering calculations and corrective actions taken to resolve
deficiencies in the engineering calculations to validate the operability of the turbine-driven
auxiliary feedwater pump (TDAFWP). The licensee had initiated, but was unable to finalize,
these evaluations during the specialinspection of engineering and licensing activities, and
review of the final calculations was identified as an unresolved item,
b. Observations and Findings
i
ACR 13426, dated May 22,1996, was initiated to address deficiencies noted in the
NUSCO engineering calculation 91074 324M3, Rev. 0 (dated March 26,1983) used to
validate the operability of the TDAFWP The corrective actions to resolve the ACR l
included the acquisition of additional performance data for the turbine, the preparation of l
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new engineering calculations, revision of the associated component specifications and the
l FSAR. The inspector reviewed the new engineering calculations (Proto Power Calculation ;
j 97 014 for TDAFWP performance and Proto Power calculation 97 000 for pressure loss) *
l- and found them appropriate and comprehensive. They were based on the new turbine
performance data and included detailed estimates of pressure losses in the intet and
exhaust piping for the pump turbine. The calculations addressed the deficiencies noted, l
'
superseded the calculations in question, and demonstrated the capability of the TDAFW to
satisfy design requirements. The inspector reviewed the procuroment specification (SWEC
l specification No. 2275.200 041) and the vendor specification (Terry Turbine specification {'
l No OIM 041003A) and verified that they and the Design Basic Document Package MP3-
i FWA for the AFW System, were modified to reflect the corrected performance
l requirements. Since the corrective actions include the performance of a flow test to
assess the potential for flow induced vibrations, the inspector discussed the proposed test
with the technical support engineer responsible for its performance. The engineer showed -
a clear understanding of test objectives, +
i
c. Conclusions ;
l
l
The inspector concluded that the new calculations prepared by the licensee for ACR 13456
l correct the deficiencies noted in the original calculation and provide the basis for evaluation ,
i of the TDAFWP overall performance. The revised estimates of performance parameters
show that the turbine / pump unit can meet design flow / power requirements. The affected
unit performance specifications were corrected to reflect the revised performance
parameters. Based on these findings, URI 96 201-40 is considered closed. -
E8.0 (Closed) Sll item 16: Dual Function Valve Control and Testina 4
a. Insoection Scoce (92903)
In 1993 Millstone. Unit 2 identified a problem with the operation of air operated valves in
the letdown line. Specifically, the air actuator spring preload was not properly set such
that adequate closing force was not available to close the valve against full reactor coolant
system pressure. The inspector reviewed the licensee's evaluation for the applicability of
this issue to Unit 3.-
b. Observations and Findinos
The cause of the problem on Unit 2 was attributed to a lack of procedures for performing
maintenance on the valve actuators which resulted in the incorrect actuator spring preload .
_
. adjustment,
l
A review of this event by Unit 3 personnel concluded that this issue was not a concern on
Unit 3. . This conclusion was based on the following:
e When the valves were purchased, a valve specific specification sheet was provided
for each Unit 3 air operated valve. The specification sheet included the maximum
required shutoff pressure for the valve,
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63
e The valve actuators were set up by the vendor to operate at the maximum shutoff
pressure and the valve nameplates specify the air pressure bench settings that will
result in the proper actuator spring preload,
e Unit 3 maintenance procedures contain provisions for controlling the actuator
settings and for post maintenance testing to verify the actuator operates at the
bench settings on the valve nameplate,
c. CDDChtSLons
The inspector reviewed valve specification sheets, maintenance procedures and a sample
work order that performed rnaintenance on an air operated valve. Based on these reviews
and discussions with licensee engineers, the inspector concluded that the licensee had
adequately evaluated the event for applicability to Unit 3. Controls in place on Unit 3
should prevent a similar event on Unit 3. SIL ltem 16 is closed.
E8.7 [C1gicd) Insoection Fajlowuo item No. 50-423/96 0817. (SIL 76): Fuse Ferrule
Cracks
'
a. Insocction Scone (37551-10)
The fuse ferrule cracks became a concern when on September 11,1996, the
licensee found several fuses (Shawmut Amptrap Cat # A2Y10) with axial cracks on
their ferrules, that has been drawn from the warehouse for installation in Millstone
Unit 3 (MP3). At that time, the licensee had developed a detailed plan to segregate
i
all suspect fuses in the warehouse; to perform a 10 CFR Part 21 evaluation, and to
perform an operability determination of fuses installed in all units, in addition, the
licensee, af ter consultation with fuse manuf acturers and other utilities, had
determined that the fuses with hairline cracks on the ferrule were capable of
,
performing the intended design function based on the available industry experience.
However, the licensee decided to perform an additionalindependent test to verify
this industry position,
b. Observation and Findina_ s
The inspector noted that the fuses manuf actured with brass ferrule material are
suspectable to stress corrosion cracking, due to the brass ferrule material relieving
internal stresses built up during the forming and crimping process. Both the fuse
manufacturers (Gould Electronics by 1994 and Bussmann by 1985) had addressed
this issue by changing the ferrule material design to a bronze or pure copper.
The inspector determined that the licensee had performed an operability analyses on
installed fuses and concluded that all fuses installed in the station were operable.
The fuses with cracked ferrules met the required resistance values, cuvent carrying
capacity, clearing time-current requirements at 200% and 500% for the time delay
fuses, and interrupting capability higher than expected values.
.
.
The inspector also reviewed the licensee's engineering evaluation of Millstone
Station (Unit Nos.1,2 and 3) concerning cracked fuses ferrule defects and noted *
that the licensee had appropriately issued a 10 CFR 21 notification report to the
NRC on December 13,1990. The report lodicated that the cracked fuse ferrule
problem existed in a variety of fuses from different manufacturers and indicated that
fifteen different type of fuses from three different manufacturers (Gould Shawmut,
Bussmann, and CEFCO) had axial cracks, as a result of the brass ferrule relieving its
internal stress as described above. The inspector noted that the licensee had
completed the following planned corrective actions:
1. Procurement and warehouse groups had completed inspecting all fuses for
cracked ferrules and replaced suspect fuses with newly procured fuses.
2. A metallurgical ana!ysis on defective fuses was performed to determine the
cause of the ferrule cracks. The analysis was found consistent with industry
l data.
l 3. Conducted an indeperdent functional testing on defective fuses. The results
! from the testing indicated that the fuses met their intended function of
maintaining electrical continuity and interruptinD the current during overload
and electrical f ault.
4. Established an appropriate certificate of conformance material type of
requirements in their procurement documentation to purchase new fuses to
ensure fuses being ordered were of new construction design either brass
pure copper. Procurement also notified the manufacturer of this defect and
confirmed determined that they had taken corrective measure to address this
concern.
5. Completed the operability determinations on each Millstone unit and their
evaluation concluded that the fuses installed were operable. Engineering
, departments of each unit has established a listing of safety related
distribution fuses to include affected fuses. The license found that no
defective style fuses were installed in Millstone 3. The licensee has elected
to replace the defective style fuses in other units by an attrition basis as per
their established routine preventive maintenance program.
6. Enhanced the procedure (NPM1-003, Rev. 2, by adding a note in it that if the
material appears defective, material should be provided to the procurement
engineering group for evaluation.
The inspector randomly verified fuses stored in the warehouse and found that all
fuses were free from above concern. The inspector also inspected fuses installed in
electrical distribution equipment, such as switchgear, control power centers, motor
control centers, and electrical distribution panels and verified that fuses installed in
Unit 3 were not of a defective style fuses and exhibited no concern. The inspector
noted that the fuses were properly labeled and easily identifiable.
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c. Conclusion
l
The inspector concluded that the licensee had done an excellent job to resolve the
fuse ferrule crack concerns at the station. Specifically,in Millstone Unit 3, most of
the electrical distribution system fuses has been inspected and replaced with
appropriate size new one with no cracks. The licensee en0ineering staff has
conducted a through analysis to verify the industry position on fuse ferrule cracking
to assure that the fuses installed in the station meet its intended design function.
This item is closed.
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66 ,
jy Pla_nt Runnort
(Common to Unit 1 Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry Controls
R 1,1 Review of ALARA Pagam
a. insoection figspe (83728 and 92904)
The inspector reviewed the licensee's program for maintaining occupational exposures
ALARA, including work control and planning, pre job ALARA reviews, post Job ALARA
reviews and management involvement in the ALARA program. The Inspector also reviewed
actions taken to address previously identified violations of NRC requirements in the area of
radworker performance.
b, Observations and Findinag
Unit 1
Unit 1 established an ALARA Council through the implementation of procedure RPM 1,4.3,
Rev 0, " Unit 1 ALARA Council." Council membership consists of the Directors for
Operations, Work Management, Maintenance and I&C, Engineering and Support Services,
together with thu Radiation Protection Manager (RPM). The inspector reviewed the
activities of the council by discussion with members of the Unit ALARA staff and review of
the Council meeting minutes Prior to the establishment of this council, unit management
involvement in ALARA activities was minimal, and thus creation of the council and
participation at the director's level represents an improvement in the program.
For 1997, the unit ALARA goal was recently lowered by 200 person-rem to 198 person-
rem, to reflect'the very limited amount of work still to be performed during the remainder
of 1997. Through July 10th, unit occupational exposure was just above 164 person-rem
and was tracking well against licensee projections. Following the decision to defer most
work in'the unit until 1998, the ALARA staff began closing most ALARA review packages,.
obtaining worker comments , and compiling lessons learned. When work recommences,
,
these reviews will aid in establishing appropriate ALARA controls on these unfinished jobs.
During the last specialist inspection in this area (NRC Inspection 50 246/97 02), several
examples of improper radworker practices were identified. Subsequent to that incpection,
the licensee undertook a Common Cause analysis, documented as " Adverse Trend in
Personnel Performance Across Millstone Site." This analysis concluded that there were-
four primary root causes, three related to management. Of significance was the
recognition in the analysis that radworker practice problems were not solely a Radiation '
Protection Department issue but was a site wide problem requiring actions be taken by all
radiological workers and their supervisors. While many of the corrective actions required to
- address the findings were not implemented at the time of this inspection, the heightened
awareness by radworkers and their supervisors was evidenced by the significant reduction
in the number of documented instances of improper radworker practices. This was
.-
67
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confirmed by the results of the inspector's observations of radworkers in the Radiologically
Controlled Areas iRCA). Actions taken in Unit 1 included training sessions and unit
walkdowns conducted by the RPM, and a reduction in the number of access points into the
unit RCA.
Unit 2
Unit 2 has established an ALARA Committee which includes representatives from each of
the major departments and is chaired by the Uni.t Director. Meetings are held every two
months at a minimum, and the directors of the major unit functional areas are required to
attend at least two of the Committee meetings in person As part of this inspection, the
inspector attended the ALARA Committee meeting held on July 10,1997. The inspector
noted the scope and depth of discussions held during the meeting as being appropriate.
Committee mernbers were observed being proactive in their discussions and actions to
address personnel exposure issues and to plan for improvements in the ALARA program.
The annual exposure goal for the unit remains at 182 person rem, and a summary of daily
exposures is presented daily at the Unit Director's morning staff meeting and reviewed in
detail. Exposures were on track with the licensee's predictions, and the unit goal continues
to appear attainable.
Unit 2 had experienced the largest number of documented instances of improper radworker
t
practices, three each cited in NRC InspectiN Reports 60 336/97 01 and 50 336/97 02.
Since the last specialist inspection in this area, however, no additionalinstances have been
identified. As part of this inspection, the inspector toured the containnient and auxlhary
buildings observing work areas and radworkers. No radworker discrepancies were
identified by the inspector. Enhanced controls included the closing of some satellite RCA
access areas, the continued assignment of a health physics technician to check workers
dosimetry prior to RCA entrance and more effective posting of the main RCA access door.
Unit 3
Unit 3 had the largest amount of work and workers in the RCA at the time of this
inspection. The unit ALARA goat remained at 134 person rem, and exposures were
tracking well with the predicted values. Significant radiological work still to be completed
included the replacement of all four reactor coolant pumps. Activities in support of the
ALARA area remained weak, especially those actions outside of the Health Physics
Department. No ALARA Committee has been formed at Unit 3, which was identified as a
weakness in a recently completed Nuclear Oversite Audit, MP 97 A06-02, * Radiation
Protection," dated June 27,1997. In addition, work control and planning remain very
arratic and incomplete at the unit with respect to advanced planning and scheduling. An -
earlier attempt at creation of a 12 week planning schedule was suspended in the spring in
f avor of an outage planning and management system. That too was abandoned after only
two months, with the, unit again looking at a 12 week planning schedule, in general,
occupational exposures at Unit 3 have remained low due to the very low dose rates found
at the unit, not because of any efforts in support of an ALARA program. Discussions held
with the Unit Vice President / Recovery Manager indicated that the ALARA program
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68
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weaknesses were clearly recognized as needing management attention, and that the
creation of an ALARA Committee was also to be addressed.
Improper radworker practices were identified in NRC Inspection Report 50 423/97 02.
Since that specialist inspection, the Unit has significantly upgraded the level of interaction
and briefings given to radworkers prior to entrance to the RCA through the main RCA
controi point, located at the entrance to the auxiliary building. The entrance was also
recently equipped with a turnstile that could only be activated if the redworker placed both
his electronic dosimeter (ED) and thermoluminescent dosimeter (TLD) in it. This is utilized
to reduce the chances of a worker accessing the RCA without having the appropriate
dosimetry with him. The inspector observed workers entering and exiting from this area,
auxiliary building. All workers observed had proper dosimetry and were aware of their area
dose rates.
The inspector also attended a training committee meeting hosted by Unit 3 involving
radworker training. At the time of this meeting, all station training was suspended, and the
major theme of this meeting was to identify and resolve allissues related to radworker
training so that this program could recommence as soon as possible (Radworker training
recommenced on July 10,1997). The inspector noted that the Training department staff
present served as facilitators, but that ownership of the training program clearly rested
with the units. Good coordination and communications between the three unit RPMs was
also observed.
Site Health Physics
The inspector reviewed parts of the site radiation protection program under the direction of
the Site Health Physics Manager and his staff. The inspector reviewed Condition Reports
(CRs) and other records maintained by this staff for compliance with NRC rules and
requirements. Allincidents and events requiring a CR by station procedure were found to
be so documented. The inspector also discussed with the Site RPM and his staff an event
involving the discovery of an unlocked door to the trailer located at the radweste bunker on
May 5,1997. This event was not documented as a CR, nor was a CR required. The event
was documented in the Site Health Physics Support Groups daily log book. Following
conversations with the inspector, the Site RPM determined that, although not required, for
tracking and trending purposes, a CR should be written to document the event.
Subsequently CR M1971685 was written on July 9,-1997,
c. Conclusions
The program for maintaining occupational exposures ALARA at each of the three units
remains weak. While the framework for an ALARA program has been implemented at
Units 1 and 2, with the creation of an ALARA Committee and the implementation of an
operational work control and work planning group, neither have been established for a long-
enough period to fully evaluate their effectiveness. The continuing lack of an effective work
control and planning process together with the lack of a unit ALARA Committee at Unit 3
continues to be of concem, however. Licensee actions to address radworker practice
issues have been generally effective, although long term actions are still being
implemented.
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R5 Staff Training and Qualification in Radiological Protection and Chemistry
Controls
R5.1 Health Physics " Supervisors Walk Around",
a. lnsoecilon Scone (71760j
On June 25,1997, the inspector participated in a health physics (HP) " supervisors walk-
,
'
around" with the radiation protection manager (RPM). Plant management sponsored the
plant walk arounds in order to raise the HP awareness of supervisors observing day to day
l work activities in the field. The walk arounds were (nandatory of all Unit i supervisors,
b. Observations and Findinas
The walk around was conducted by the RPM and began outside the radiological controlled
area (RCA) with a review of the radiological work permit system and the proper use of
electronic dosimetry. Once inside the RCA, the RPM discussed the operation and use of
the small article monitor (SAM) and personnel contamination monitor. A primary focus area
'
for the walk around was the use of reusable materials in the plant, particularly in the area
of FME control. The RPM stressed the fact that limiting the amount of disposable material
brought lato the plant, results in a reduction in radiological waste (RW). Plans for a " hot
tool" locker in the plant were also discussed.
The tour was extremely informative and provided good insights into RW reduction. The
walk arounds received very good response from the plant staff and as of the end of June,
78 of 80 Unit 1 supetvisors attended, and 79 additional personnel participated in the
activity, including individuals from Unit 3. The inspector was informed that additional
walk arounds are planned for other HP areas, for example HP posting and boundaries, as
well as, walk arounds in the areas of security and nuclear oversight.
4
c. Conclusions
Plant management sponsored the plant supervisors walk arounds in order to raise the HP
awareness of supervisors observing day to day work activities in the field. The walk-
around tour was extremely informative af.d provided good insights into radiological waste
reduction. The initiative as well received by the Unit 1 supervisors and will be expanded to
included additional ares such as security and nuclear oversight.
PA Staff Knowledge and Performance in Emergency Preparedness
P4.1 Dfill Evaluation Scoce
a. - insoection Scapg
During this inspection, the NRC inspectors observed and evaluated the performance of the
-licensee's site emergency response organization (SERO) during the drill in the simulator
control room (SCR), technical support center (TSC), opcrations support center (OSC), and
- /
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70 .
the emergency operations f acility (EOF). The inspectors assessed licensee recognition of
abnormal plant conditions, classification of emergency conditions, notification of offsite
agencies, devdopment of protective action recommendations, command and contrul,
communications, and the overallimplementation of the emergency plan. In addition, the
inspectors attended the post exercise critique to evaluate the licensee's self assessment of
the drill,
b. Qhtetystions and Findings
Emergency Resoonse Facilitv Observations and Crittaus
Simulator ControLBoom (SCR)
During this drill, the shif t manager demonstrated excellent command and control of the
operations crew Good internal communications were evident between the unit supervisor
and the control board operators, to include strong ' repeat back techniques, good use of
the alarm master silence" feature, and proper use of the emergency operating procedures.
The shif t manager conducted initial classificatior of the event at the " Alert" level in a
timely manner and with proper consideration of the criteria delineated in the event
assessment procedure, EPIP 4400. Communications with the technical support center
(TSC) was established and maintained effectively. However,it was noted that the shift
manager transferred the responsibility for emergency classification to the assistant director
of technical support before full TSC functional capability had been verified and that this
transfer of duties was not announced to the control room staff at the earliest opportunity.
Once a direct communications link was established with the TSC, frequent briefings and
discussions took place on plant conditions, equipment status, and the analysis of this -
event. The control room staff was particularly effective in discussing options and operating
decisions with TSC personnel before commencing or altering planned evolutions. This
deliberative coordination was found to be in evidence in the decisions to start and then
secure the *C" charging pump, to not reopen the accumulator isolation valves af ter
resetting the initial safety injection signal, and to start and secure quench spray pump
operation as necessary. Also, the shif t manager performed wellin assessing and projecting
the potential for further radiation barrier ' degradation and in discussing the appropriate
recommendations with the TSC staff. One area where coordination between the control
room and the TSC could have improved was the control and tracking of various support
personnel (e.g., chemistry, health physics, field teams) that were dispatched for work
activities from either of these two locations without the clear and direct knowledge of all
concerned managers and/or coordinators.
The control room staff had a good focus on maintaining a safe'and stable unit, given the
changing plant conditions and equipment abnormalities. The unit supervisor conducted
appropriate critical safety function reviews and worked with the shift manager in
prioritizing control room activities and evolutions and in attempting to provide "real time"
information to both the.TSC and the Emergency Operations Facility (EOF). Anomalous
plant conditions (e.g., increasing containment pressure indications an6 iadiation levels)
were diagnosed and discussed by the licensed control room operators with input from the
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shif t technical advisor and station duty officer, to provide both the TSC and EOF with the
best collective analysis of what might be causing any observed worsening emergency
conditions.
One area where better external control room communications and coordination could have
been provided was that of the " turnover" of functional responsibilities to designated
personnelin the other facilities, in addition to the possibly premature transfer of event
classification duties discussed above,it was noted that the station duty officer delegated
the responsibility for initially notifying NRC headquarters of the " Alert" to the EOF
information officer before the shif t manager had turned over command and control of the
emergency to the Director of Station Emergency Operations (DSEO). It is routinely
expected that the initial telephone communications with the NRC duty officer would
originate from the control room, vice the EOF. Also, the shift manager's turnover of
command and control to the DSEO appears to have occurred prior to actual activation of
the EOF.
While some turnover and coordination problems involving the control room's interaction
with both the TSC and EOF were observed, the overall response of the licensed operators,
shif t management, and the entire control room crew were determined to be good, with
positive impact upon both the assessment and steps taken to mitigate the emergency
conditions.
Technical Succort Center (TSC) Ooerational Sucoort Center J.QSQ
The TSC was staffed and activated in a timely manner. The Assistant Director of
Technical Support (ADTS) exhibited strong command and control, and maintained good
communications with the simulator control room throughout the drill. The ADTS conducted
a good turnover from the shift manager and ensured that his staff was briefed prior to
activation. However, the ADTS accepted responsibility for emergency classification from
the simulator control room prior to officially activating the TSC. Additionally, the inspector
noted that there was some confusion as to when the TSC was activated.
Event classifications were correct and timely, and notifications of offsite officials were
'
appropriately initiated. Although, after the declaration of the Site Area Emergency (SAE)
and the General Emergency (GE), the declarations were not announced to plant personnel
via the public address system. In evaluating the Emergency Action Levels (EALs) for
escalating from a SAE to a GE, the ADTS was noticeably focused on the barrier failure
portion of the EALs, and the barrier failure reference table. The apparent difficulty in the
use of this portion of the EAL distracted the ADTS from other applicable EALs. As the drill
progressed, the ADTS was reminded by the Director of Site Emergency Operations (DSEO)
in the EOF, that a GE can be declared directly from the in-plant radiation EAL regardless of
barrier failure criteria,
During regular and frequent briefings, the ADTS ensured that priorities were properly
established and understood by both the TSC and OSC members. The Manager, Operational
Support Center (MOSC) and the Manager, Technical Support Center (MTSC) were both
given the opportunity to provide a status of reports at each of the briefings. This allowed
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for the close coordination of activities between the TSC and the OSC. Three way
communications (repeat backs) were consistently and effectively used by all TSC/OSC
'
members. The ADTS kept the TSC staff thinking ahead in anticipation of changing plant
conditions by the use of a white board and continually asking the question, "What can go
wrong?" The use of backup ADTSs during this drill was excellent in that it removed some ,
of the administrative and communication burdens from the ADTS.
'
The MTSC coordinated with the accident management team to evaluate potential adverse
consequences of the events, keeping the ADTS advised of the changing priorities. The
accident management team played an important role in assessing the scenario in light of
erroneous information (containment radiation levels) from the simulator control room.
'
The ADTS appropriately established and adjusted the priorities of emergency repairs. The
MOSC maintained a good command and control over the OSC. Team activities were
closely monitored and teams were dispatched in an orderly f ashion depending on changing
priorities. All OSC teams were briefed by HP prior to being dispatched.
Emercenev Ooerations Fad 1RyEREl
'
Good command and control was demonstrated by the Director of Site Emergency '
Operations (DSEO) and the Assistant Director of the Emergency Operations Facility
(ADEOF). The DSEO gave thorough briefings to the EOF staff. The DSEO effectively used
the team leads to provide information to the other staf f members during the briefings in the
emergency operations center. However, it appeared that the DSEO was having problems
getting the plant status information through the open link used to transfer information from
the simulator control room and the technical support center. This lack of information could
have been a hindrance in some of the decision making in formulation of the protective
action recommendations provided to the state of Connecticut.
The technical information coordinators did a very good job in maintaining the status boards
and informing the DSEO of plant conditions as they changed, through di_ rect-
communications from the simulator control or from the Offsite Facility Information System
(OFlS).
The ADEOF's performance in preparing the PAR for the DSEO using the new, approved
PAR procedure in formulating the initial PAR on plant conditions at the general emergency
and the PAR upgrade which was caused by a change in plant conditions later in the drill
was good. Because the new PAR procedure is the same for Haddam Neck, and it was
adequately demonstrated during this drill, the Haddam Neck violation on formulation of
PARS is closed.
L
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Dose Assessment
I The radiological dose assessment team monitored plant parameters and calculated the
number of the curles of noble gases in the containment based upon the containment -
radiation monitor reading. The dose assessment team informed the Assistant Director
Emergency Operations. Facility (ADEOF) of the dose consequences which may occur if the
o
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entire containment source term was released from the worst release point. This
information was used in providing a worst case estimate of potential consequences, but
could cause inappropriate protective action recommendations (PARS) to be issued if the
recommendations were based upon this information. The ADEOF considered this
information, but properly based his PAR upon the current plant conditions as a release was
not ongoing nor predicted to occur. It would have been beneficial for the dose assessment
team to provide adoitional what if" calculations for other release points and other release
magnitudes.
Although the radiological dose assessment team was able to make dose projections and
position field teams to monitor the release, the following at.pects of the radiological dose
assessrnent was not well performed:
- Dose assessment personnel were not proficient in the use of the Offsite Facility
Information System (OFIS). OFIS can be used to monitor containment radiation
levels and vent stock monitor readings.
- When it was discovered that the OFlS readings legged the actual plant readings, the
dose assessment team did not aggressively pursue obtaining more timely radiation
rnonitor data from another source.
- The start of the release was not quickly identified by the dose assessment staff and
was not clearly communicated among the EOF staff and field monitoring teams.
- Dose projection calculation sheets were not properly filled out. One of the dose
assessment sheets contained an error and other calculational sheets did not have all
the pertinent data entered. Sheets were not signed and dated. Very little hard copy
dose projection data was printed out. This data could have been usefulin tracking
the update in dose projections during the event and would have been useful in
evaluating the dose projections af ter the event / drill.
Licensee Drill Critiaug
The licensee's critique was very comprehensive and thorough. It identified all of the
observations identified by the NRC inspection team,
c. Overall Drill ConglyMons
Overall performance of the SERO was good. Simulated events were accurately diagnosed,
proper mitigation actions were performed, emergency declarations and protective action
recommendations were timely and accurate, and offsite agencies were notified promptly.
No drill weaknesses, safety concerns, or violations of NRC requirements were observed.
i
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4
P8 Miscellaneous Emergency Properedness issues
a. Inspection SAQDa
On Tuesday, June 17,1997, the inspector and Emergency Preparedness and Safeguards
Branch Chief met with the Northeast Utilities Director of Ernergency Preparedness and his
staff and were presented with the " Millstone Station Emergency Planning Status."
The presentation included past issues, issue resolution, emergency planning elements that
-were in progress, milestones completed, and milestones remaining. A copy of the
presentation handout is attached. The corrective measures being taken are appropriate,
b. Observations and Findings
The inspector' observed a test of the new dialogic callout systems that is scheduled to I
replace the present system that is currently in use. The pagers were activated at
approximately 7:00 p.m. on June 18,1997. It was demonstrated to the inspector by
calling into the system that the initial call backs seemed to overload it initially, but within 2
to 3 minutes we were able to callinto the system. Within about 20 minutes, the callout
was complete.
>
.A message was displayed on the beepers that if there were any problems getting into the
system that personnel were to contact the emergency preparedness services department.
There were several instances where the PIN number for the beeper holder did not work
properly and that was to be corrected.
The system appeared to function and made timely notification to the site emergency
response organization.
Further tests of the system are to be performed before placing it into operation.
F1 Control of Fire Protection Activities
F1.1 Program Oversicht
a. Innocction Scone (64704)
The inspector reviewed fire protection program policy changes made by licensee
management to improve program oversight. This review was performed as a result of
previous NRC inspection findings, as documented in inspection Report No. 96 08,
Section F.
b. Observations and Findinos
The inspector found that the licensee continued development of the Fire Protection Program
Manual. Although lacking supervisory approval of the manual, the inspector reviewed the
licensee's documented efforts for integrating design features, personnel requirements,
,
_ _ _ _ _ _ ___.
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75
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equipment, and procedures to ensure fire protection requirements are met. Following
document approval, the licensee plans to develop supplemental guidance documents,
project instructions, to the manual for controlling fire hazards analyses and 10 CFR Part 50,
Appendix R analyses.
l
The inspector found the manuel improved over Nuclear Group Procedure (NGP) 2.14, I
Revision 9, ' Nuclear Plant Fire Protection Program / and reflected the program
organizational changes to date, better defined individuals responsibilities, and appropriately
established a single point of et trol and contact for improved program implementation, in
addition, the inspector noted tl.at information pertaining to the design and licensing
requirements for the three Millstone plants was contained within the draft manual. The
inspector noted that the manual presented an expanded view of fire protection comrw-
the NGP. More specifically, the inspector found that the manual applied to fire
structures, systems, and components important-to safety in t,ddition to safe w
safety related equipment. Although fWlimplementation of the licensee's cc a
had not been completed, and subsequently the inspector could not evaluate
effectiveness of such actions. the inspector concluded that positive measures were taken
by a competent staff foi establishing a good fire protection program and consistent
approaches for maintaining the prograta in accordance with NRC requirements. The
inspector noted that the manual was approved without any changes from the draft version
reviewed during the inspection on July 2,1997, by the Site Operations Review Committee
- (SORC) and on July 9,1997, by each Millstone unit Plant Operations Review Committee
'
(PORC).
Corrective actions taken by the licensee to improve the effectiveness of engineering
i
support for the fire protection program, as discussed in Inspection Report 96-08, Section
F.1, were not evaluated during this inopection and will be the subject of future NRC review
prior to restart of any Millstone unit. (IFl 97 202 10) The acceptability of the licensen's
corrective actions will be used to subnantiate closure nf NRC safety issues list (SIL) issues
Nos 65,21, and 42 for Millstone Units 1,2, and 3 respectively.
The inspector found that corrective action taken by Northeast Utilities included the
performance of an engineering self assessment (ESAR) No. PES-97-0006, Revision 0, for
evaluating the licensing commitment control, configuration management, technical
adequacy, and effectiveness of the Unit 3 fire protection / Appendix R program. This
assessment was conducted by on independent team and resulted in numerous deficiencies
and corrective actions. The licensee stated that ESARs were planned for Units 1 and 2
also. The inspector determined that the ESAR w:.s comprehensive for verifying compliance
with regulatory requirements and qualitative for recommending corrective actions that
would ansure an effective fire protection program. The inspector found that license
commitments were extensively summarized with background and reference information
sufficient to verify proper plant configuration and adequacy.
e. Conclusion
The inspector concluded that significant nusgress had been made by the licensee in
improving the overs ght and organization of the fire p ohetion program. Although planned
__ .-_ -.__ _ _ --.---- ___________ ____ _ _ _
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76
corrective a:,tions were found to be comprehensive, further NRC review is necessary to
verify the proper implementation of the planned currective actions.
F4 Fire Protection Staff Knowledge and Performance
F4.1 Fire Briaade Drill
a. Insoection Scoce (64704)
The inspectors observed an unannounced fire drill to evaluate the effectivehess of the new
centralized, fire brigade, the drill scenario, and the drill critique. This observation was made
as a follow up to previously identified drill weaknesses, as documented in NRC inspection
report 96-08, section F4.2.
b. Observations and Findings
The inspector observed a fire drill on June 24,1997, that involved a simulated motor
control center breaker fire in the turbine building of Unit 1. The inspector observed the
brigade response, dress out, simulated attack strategy, and command and control
demonstrated by the brigade captain. The inspector found that many improvements had
been implemented by the licensee. Scersario cards were utilized at the fire scene to
describe fire conditions and enable fire brigade members to size-up the situation and
[ develop their fire fighting strategy. A newly created position of fire brigade advisor was
l utilized as an Operations department liaison, communicating information between the
l control room and brigade captain. An emergency response vehicle was used to expedite
brigade arrival at the fire scene by transporting fire gear. A pre-drill meeting was held *(o
better ensum proper drill coordination and evaluation by both the Training and Site Fire
Protection departments, and a post drill caucus was held prior to the drill critique to ensure
consistent feedback was provided to the brigade regarding their performance.
. t
The inspector found that:
- the drill scenario was realistic;
- excel:ent support was provided to the brigade captain by the fire brigade advisor;
- the fire captain demonstrated outstanding command and control and verified self-
checks were perfor Ted by the brigade, properly reviewed the pre-fire plan, and
made team assignmen.a accordingly;
e drillmanship and teamwork were robust; and
- the drill critique properly reflected brigade member performance.
_ - _ _ _ - _ _ _ _ _ _ _
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c. Conclusion
The inspector concluded that the fire brigade functioned effectively and was well prepared
to combat fires. Significant improvements were implemented by the licensee that
!
contributed to overall sunerior performance displayed by the Training and Site Fire
Protection Departments associated with the fire drill. The inspector considered the drill to
be outstanding and concluded that significant improvement was displayed by both the
brigade and training departments.
F7 Quality Assurance in Fire Protection Activities
F7,1 Audits and Surveillsnees
a, insoection Scoce (64704)
The inspector reviewed the most recent audit completed by the Quality Assurance (QA) I
Nuclear Oversight Department to satisfy the technical specification requirements, The
audit evaluated the effectiveness of fire protection measures, equipment, program
implementation; and problem identification and resolutlen. This review was performed
following previously identified audit weaknesses as documented in NRC Inspection Report
No - 90-08, Section F7,1,
b, Observations and Findinos
The inspector reviewed audit no. A24057/A25119, " Triennial Fire Protection program -
Millstone," dated March 10,1997, and found that the audit;
- was comprehensive and appropriate in scope;
- = demonstrated good problem identification;
- appropriately followed up on previously identified QA findings: and
e clearly communicated findings in reports.
c, Conclushn
The inspector concluded that this OA audit provided a good assessment of the fire
prctection program and satisfied the technical specification requirement for performance.
The inspector noted an improvement in the assessment quality over previous audits of the
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78
'-
,
V. Management Meetings
- X1T Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at
. separate meeti ngsi n each unit at the conclusion of the inspection. The licensee
acknowledged the findings presented.
,
- X1.2 Final Safety Analvsis Reoort Review
A recent discovery of a licensee operating their facihty in a manner contrary to the updated
final safety analysis report (UFSAR) description highlighted the need for additional
. verification that licensees were complying with UFSAR commitments. All reactor
inspections' will provide additional attention to UFSAR commitments and their incorporation
into plant practices, procedures and parameters.
While performing the inspections which are discussed in this report the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The following
,
inconsistencies were noted between the. wording of the UFSAR and the plant practices,
procedures and/or parameters observed by the inspectors, as documented in Sections
U3.M1.3, U3.M3.2, and U3.E3.4.
.
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ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
URI 50 245/97 202 01 U 1.E8,1 RWCS filter cubicle inspection i
URI 50 336/97 202 02 ULE8.6 Main steam check valves design adequacy I
IFl 50 423/97 202 03 U3,01.1 Loss of spent fuel pool cooling
VIO 50-423-97 202-04 U3 M1.4 Failure to follow procedures
!Fl 50-423/97 202 05 U 3,M 3,1 Testing of safety / relief valves
eel 56 245/336/423/ U3 M4,1 Ineffective maintenance and technical training
97 202 06 evaluation
,
IFl 50-423/97-202-07 U3.M8.4 Letdown heat exchanger ASME code compliance
l~ VIO 50-423/97 202-08 U3 E7.1 Incomplete and inaccurate information
[ eel 50 423/97-202-09 U3 E8,3 RSS design deficiency
IFl 50-423/97 20210 U 3,F 1.1 Engineering support of fire protection program
Cloted
URI 50-245/94-14-03. U 1,M8,1 QA involvement in safety related work
IFl 50-336/95 201-03 U2.M8,1 Procedure level of use
IFl 50-336/93 20-05 U2,E8.2 Testing of dual function valves
URI 50 336/96-0814 U2 E8.3 Remc, val of startup rate trip
URI 50-423/96-08-18 U 3,M 8,1 Adequacy of IST program
URI 50-423/96 20140 U3,E8,5 - TDAFW calculations
- Uodated
eel 50 336/96-201-25 U2,E8,1
eel 50 336/96 20136
~
U2,E8.4
eel 50-336/96-201-42 U2 E8,5
eel 50-336/96 201-43- U2 E8,5
LER 50-423/9515 02 U3 E2,1
URI 50-423/95-07-10 U3,E3.5
eel 50-423/96-20121 U3 E8.2
eel 50-423/96-201-24 U3,E8,3
The followina LERs were also closed durina this insoection:
Docket Number 50-336
97-04
97 11
,
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Docket Number 50-423
96 34
96 50
97 03
97 14
97-15
97-22
97-23
97-24
97 26
97-28
4
s
$
)
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81
LIST OF ACRONYMS USED
ACP(s) administrative control procedure (s)
ACR(s) adverse candition report (s)
ADEOF Assistant Director of.the Emergency Operations Facility
ADTS . Assistant Director of Technical Support
AITTS action item tracking and trending system
ALARA as low as reasonably achievable
ANSI /ANS ' American National Standards institute /American Nuclear
AOO(s) anticipated operational occurrence (s)
l ASME American Society of Mechanical Engineers
l A W O(s) automated work order (s)
BOM bill of materials
CAC(s) curriculum advisory committee (s)
CCP. reactor plant component cooling
CFR Code of Federal Regulations
,
CMP configuration management plan
'
CR(s) condition report (s)
CREPS control room envelope pressurization system
DCN design change notice
DSEO Directo* of Station Emergency Operations
EAL(s) emergency action level (s)
EDG emergency diesel generator
eel escalated enforcement item
EOF Emergency Operations Facility
EOP(s) emergency operation procedure (s)
EPIP(s) emergency plan implementing procedure (s)
EPRI Electric Power Research Institute -
ERT event revie. ., team
ESAR engineering self-assessment report
EWR(s) engineering work request (s)
FME foreign material exclusion i
FP fire protection
FSAR Final Safety Analysis Report
GE General Electric
GL Generic Letter
gpm gallons per minute
HELB high energy line break
HPSI high pressure safety injection
HX- . heat exchanger
ICAVP Independent Corrective Action Verification Program
IFl inspector follow item
IHSI intermediate head safety injection
IP(s)- inspection procedure (s)
IR(s) Inspection Reports (s)
.
)
82
.
IRT independent review team
ISI inservice inspection
IST in-service testing
LER(s) licensee event report (s)
LOCA loss of coolant accident
LTOP low temperature overpressure protection
MCR Main Control Room
MEPL material, equipment, and parts list
MMOD maintenance modification
MOSC Manager, Operational Support Center
. MSIV main steam isolation valve
MTL management test lead
MTSC Manager, Technical Support Center
MSLB main steam line break
NCR(s) nonconformance report (s)
NCV non-cited violation
NDE non-destructive examination
NGP(s) nuclear guidance procedure (s)
NNECO Northeast Nuclear Energy Company's
NPS nominal pipe size
NPSH net positive suction head
NRC Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
NSAB nuclear safety assessment board
NSIC Nuclear Safety information Center
NSR nonsafety-related
NUGAP Northeast Utilities Quality Assurance Program
NUREG Nuclear Regulation
NUSCO Northeast Utili'.'es Servh.e Company
OCA Office of Congressional Affairs
OEDO ' Office of Executive Director for Operations =-
OFIS offsite facility information system
OlRls) open item report (s)
OJT on the job training
OJT/E on the job training / evaluation
OP(s) operating procedure (s)
ORP Operational Readiness Plan
OSC Operational Support Center
OSHA Occupational Safety & Health Administration
PAO Public Affairs Office
PDCR plant design change record
PDR- Public Document Room
PEO plant equipment operator
PGS primary grade water system
PMMS production maintenance management system
PORC plant operation review committee
PORV(s) power operated relief valve (s)
-
--
U
8 3 --
,y
PSTS. product' specific technique sheet
PTSCR proposed technical specification change request -
QA quality assurance
OC . quality control
QSS quench spray system
RBCCW reactor building closed cooling water
RCS - seactor coolant system
RG' Regulatory Guide
Rt Region l-
RO reactor operator
RPM radiation protection manager
l RSS recirculation spray system
i
RW~ radiological waste
SAT systems approach to training
SCR simulator control room
SERO station emergency response organization
SFPC spent fuel pool cooling
Sll significant item list
SORC site operations review committee
SOV(s) solenoid operated valve (s)
SP(s) - surveillance procedure (s)
SPO Special Projects Office
SPROC special procedure
_SR safety related -
SRO senior reactor operator
SRP - Standard Review Plan
SSPS solid state protection system
SWEC - Stone & Webster Engineering Corporation
SWSOPl ._ service water system operational performance inspection
TAC technical advisory counsel
TDAFW turbine driven auxiliary feedwater
Tl temporary instruction
TLD(s) - thermo-luminescent dosimeter (s)
TRM Technical Requirements Manual
- TS(s) technical specification (s)
_UFSAR updated final safety analysis report
UIR(s) unresols ed item report (s)
URl(s) unresolved item (s)
USO. unresolved safety question
VIO violation
.
.