ML20206F460
| ML20206F460 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/30/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206F457 | List: |
| References | |
| 50-336-99-04, 50-336-99-4, NUDOCS 9905060132 | |
| Download: ML20206F460 (77) | |
See also: IR 05000336/1999004
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U.S. NUCLEAR REGULATORY COMMISSION
~ REGION I
' Docket No:
50-336
License No:
Report Nos:
50-336/99-04
Licensee:
Northeast Nuclear Energy Company
P.O. Box 128
Waterford, CT 06385
Facility:
~ Millstone Nuclear Pov ar Station, Unit 2
- Location:
.Waterford, CT
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Dates: '
March 15-31,1999
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Inspectors:
F. Arner, Reactor Engineer, Region I DRS
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J. Blake, Region ll DRS
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P. C. Cataldo, Resident inspector, Millstone
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S. Chaudhary, Sr. Reactor Engineer, Region I DRS
'J. Cummins, Contractor
S. Dembek, Millstone 2 Project Manager, NRR
P. Habighorst, Resident inspector, Indian Point
K. Kolaczyk, Reactor Engineer, Region i DRS
D. Lanyi, Resident Inspector, St. Lucie
J. Laughlin, Resident inspector, Salem
L. James, Reactor Engineer, Region i DRS
L. Scholl, Reactor Engineer, Region i DRS
J. Zach, Contractor
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. Team Leader:
J. Trapp, Senior Reactor Analyst, Region i DRS
Approved by:
James C. Linville, Chief
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Millstone Branch, Region l
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9905060132 990430
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' ADOCK 05000336
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TABLE OF CONTENTS
PAGE
EXEC UTIVE S U M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
' I. Management Programs & Oversight . . . . . . . . . . . . . . . . . . . . .
.....................1
S1
M a nagement Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
S2
Corrective Action Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
S3
Independent Oversight . . . . . . . . . . . . . . . . . . . . . . . . .... ............ 7
S4
Quality Review Committees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Sta rtu p Pla n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
l l . Ope ratio n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1
O1
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
02
Operational Status of Facilities and Equipment . . . . . . . . . . . .
................13
03
. Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
04
Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
05
Operator Training and Qualifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
06
Operations Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
07
Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
lil. Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
M1
Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
M1.1 Observations of Maintenance and Surveillance Activities . . . . . . . . . . . . . . . 24
M2
Maintenance and Material Condition of Facilities and Equipment . . . . . . . . . . . . . . . 27
M3
Maintenance Procedures and Documentation
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M6
Maintenance Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
M6.1 Maintenance Planning and Scheduling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
IV. E ngineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
E1
Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
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TABLE OF CONTENTS (CONT'D)
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E2
Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . 35
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Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . 35
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E2.2 Temporary Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
E2.3 Deferred issues Revievi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E2.4 Engineering Support to Plant Operations . . . . . . . . . . . . . . . .
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E3'
Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
E3.1 - Operability Determinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
E3.2 Vendor Manual Cont 71 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
E3.3 Setpoint Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
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E3.4
Equipment Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
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E3.5 Operating Experience Program . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . 43
E3.6 Drawing Control . .
.......... ... ....... ........ ............ 44
E8
Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
E8.1
Emergency Core Cooling Systems Single Failure Vulnerability . . . . . . . . . . .
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E8.2 (Closed) LER 97-034-00; Containment Sump Isolation Valves are Susceptible to
Pressure Locking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
V.
M anagement Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
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Exit M eeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
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EXECUTIVE SUMMARY
The OSTI findings are one input, of many, used by the Nuclear Regulatory Commission (NRC)
Restart Assessment Panel (RAP) to make a restart recommendation to the Commission. The
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OSTI concluded that plant hardware, staff and management programs are in place to support a
safe restart and continued operation of Millstone Unit 2. The OSTI conclusion is contingent
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upon the successful completion of the items identified by the licensee as required for restart.
MANAGEMENT PROGRAMS & OVERSIGHT
S1
Manaaement Processes
Appropriate standards and expectations for cafety were estabn. ,Jd by senior
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management and were understood by subordinate managers and staff. The team
concluded that management expectations for safe plant operations were communicated,
understood and followed by the plant staff. Senior plant management used a variety of
communication methods to reinforce expectations. Management expectations regarding
employee concems were understood by the staff.
Planning and direction for the restart and recovery of Unit 2 were effective. The
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application of probabilistic risk assessment (PRA) insights to design and operation of the
plant were adequate. Effective ieadership was provided and management involvement
in routine activities and emerging issues was appropriate. The Nuclear Oversight
Verification Plan (NOVP) and " windows" assessment tools were effective mechanisms
for management to assess restart readiness.
The team's findings, in addition to those of the NRC 40500 inspection team (NRC IR 50
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336/99-01), provide the basis for the closure of Significant item List (SIL) item No.1,
Management Oversight and Effectiveness; Licensee Staff Safety Culture, and the
associated NRC Restart Assessment Plan items.
S2
Corrective Action Proaram
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The overall corrective action program is adequate to support plant restart. Plant
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deficiencies are being included in the corrective action program and recent root cause
evaluations are thorough.
The team concluded that the licensee's backlog management plan was adequate. In
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addition, the team concluded that the licensee's process for deferral contained
appropriate methodology for the identification of items acceptable for deferral and
completion after the Unit 2 restart. Moreover, the team did not identify any items that if
not completed prior to restart, would have an adverse impact on the safe restart of Unit
2.
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The team's findings, in addition to those of the NRC 40500 inspection team (NRC IR
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50-336/99-01), provide the basis for the closure of SIL items No.12, Licensee Restart
Punch List - Review items Deferred Until After Restart, and the associated NRC Restart
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Assessment Plan items.
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S3
Indeoendent Oversiaht
The NOVP provides effective independent assessment of performance for resolution of
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" key issues". The Nuclear Oversight Organization's involvement in operations,
maintenance,Lsurveillance and engineering has been satisfactory. Line organization
cooperation and support for oversight activities was apparent. The tearh concluded that
the various reporting mechanisms employed by the nuclear oversight organization
provided an effective means of capturing conditions adverse to quality and en! uing that
those conditions were corrected. The reports were critical assessments and provided
senior management with a useful " snapshot" of plant performance and areas requiring
additional attention. Nuclear oversight audit findings with restart implications are being
properly addressed.
S4
Quality Review Committees
The plant operations review committee (PORC), station operations review committee
(SORC) and nuclear safety assessment board (NSAB) all meet the technical
specification (TS) requirements. At the time of this inspection, there were no outstanding
oversight committee items that would adversely affect unit restart. The team concluded
that the NSAB was providing effective independent oversight.
Startuo Plans
The team concluded that the licensee had developed detailed restart plans and
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established an augmented oversight organization for unit startup.
OPERATIONS
O1
Conduct of Operations
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The operations department had sufficient personnel to provide coverage throughout the
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restart period without excessive use of overtime. The shift turnovers observed were of
high quality with active participation from groups supporting operations. Pre-job briefings
were generally good with a few minor communications weaknesses.
The team's findings provide the basis for the closure of SIL item No.13, Operator
Performance, and the associated NRC Restart Assessment Plan items.
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02
. Operational Status of Facilities and Eauioment
The implementation of processes to establish and maintain configuration control were
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generally acceptable. However, various condition reports identified problems in the
valve lineup and tagout process that indicate implementation was not always effective.
O3
poerations Procedures and Documentation
Operator procedural quality wan generally good. Some minor validation deficiencies
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were noted in a few surveillance and emergency operating procedures; however, none
had an impact on safe operation of the facility. Appropriate procedural adherence by
operators was observed.
O4
Operator Knowledae and Performance
Operator performance was generally good and control room demeanor was observed as
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appropriate. Both licensed and non-licensed operators were aware of plant conditions
and maintenance activities in progress.
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The operators conducted plant evolutions in a safe and controlled manner, and exhibited
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a conservative approach to equiptr.ent manipulation. Generally, control room operators.
expeditiously identified plant equipment malfunctions or changes in plant conditions.
However, in one case a technical specification surveillance test requirement, to monitor
steam generator temperatures, was not performed in a timely manner. There were no
safety consequences as a result of not conducting this surveillance because the required
plant parameters were always satisfied. The failure to conduct this technical
specification required surveillance is a violation of NRC requirements. This Severity
Level IV violation is being treated as a Non-Cited Violation, consistent with Appenoix C of
the NRC Enforcement Policy. This violation is in the licensee's corrective action program
as Condition Report M2-99-1060.
Generally, operator control board awareness and annunciator response were good.
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However, on several occasions, the team observed operators failed to appropriately
communicate unexpected alarms to the Unit Supervisor.
05.
Operator Trainina and Qualifications
Alllicensed operators had satisfactorily completed requalification training. A review of
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the lesson plans, discussions with licensed operators, and observation of plant and
simulator performance indicated that the training provided to the operators was sufficient
. to ensure that they could safely restart the unit. Modification training for the operators
was appropriate to effectively communicate plant changes completed during the outage.
O6
Operations Oraanization and Administration
. Operations department staffing levels were adequate to support the safe operation of the
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plant. Communications within the operations department and with other site
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. organizations were good. Operators generally initiated operability determinations in
response to degraded equipment conditions. The team observed good command and
control of shift activities.
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Quality Assurance in Ooerations
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Nuclear oversight observations provided accurate accounts of activities involving the
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conduct of operations. Self-assessments were critical and the licensee's corective action
plans for improvement were appropriate.
MAINTENANCE AND SURVEILLANCE
M1
Conduct of Maintenance
The quality of maintenance activities observed was generally good. Maintenance
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technicians conducted good pre-job briefings in the maintenance shops and briefed
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operators on job scope prior to beginning work.
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Procedure adherence by the maintenance staff was generally good. The team observed
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instances where work was stopped to clarify or revise maintenance procedures.
The maintenance workers were knowledgeable of assigned maintenance tasks and had
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received appropriate training. The team concluded that the maintenance rework rate
was at an acceptable level, and that the licensee had adequately resolved maintenance
rework issues through the corrective action system. Appropriate maintenance
supervisory oversight of field activities was observed.
M2
Maintenance and Material Condition of Facilities and Eauioment
Necessary equipment repairs were either completed or scheduled for completion prior to
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plant restart. Maintenance backlogs were being appropriately managed and routinely -
assessed for impact on operations. The control of operator work-arounds and control
room '.ieficiencies was also found to be adequate to support plant restart. The plant
material condition and housekeeping were acceptable. The Backlog Reduction and
. WoA-It-Now (WIN) Teams had a positive impact on addressing emergent work and
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reducing the automated work order (AWO) backlog.
These findings, along with the review of temporary modifications (bypass jumpers)
documented in Section E2.2 of this report, provide the team's basis for closure of NRC
. Significant item List item 7, Bypass Jumpers, Operator Work-arounds & Control Board
Deficiencies and the associated NRC Restart Assessment Plan items.
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Maintenance Procedures and Documentation
The team concluded that procedures reviewed were generally adequate for the intended
tasks.
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M6
Maintenance Oraanization and Administration
Performance in the area of planning and scheduling was mixed. Planning was thorough,
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with detailed work packages prepared to support most AWO activities. Schedule
adherence did not meet licensee's goals primarily due to emergent issues. The team did
not observe any instances where schedule pressures or changes adversely affected
plant safety.
The licensee's performance in assessing the safety / risk of planned maintenance was
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acceptable. Safety assessments for maintenance activities were addressed by
appropriate procedures and the risk significance of planned activities was discussed at
planning meetings.
The licensee had identified and/or completed surveillance tests required for plant restart.
The team's findings provide the basis for the closure of SIL item No. 6, Work Planning
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and Control, and the associated NRC Restart Assessment Plan items.
ENGINEERING AND TECHNICAL SUPPORT
E1
Conduct of Enaineerina
The engineering department managed the planned and emergent activities well. Daily
planning of issues at the morning meeting set the priorities of both the system and
design engineering departments. Communication with and support to other departments
was good. The identification, documentation and control of issues within the condition
report (CR) system was good. Corrective actions associated with CRs and other open
items were properly tracked within the action item tracking and trending system (AITTS).
The team did not identify any CR issues that had not been properly screened and
dispositioned for deferral until after the restart.
E2
Enaineerina Support of Facilities and Eauipment -
The team found the design control process was being properly implemented. The
technical quality of changes was good and modification package content, including the
10CFR50.59 screening and safety reviews, are comprehensive. Post-modification
testing accomplished the verification of important design change attributes. The use of a
Quality Review Board has contributed to improvements in the quality of the engineering
products.
Engineering has been effective in resolving issues. As a result, the use of temporary
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modifications was minimal. The number of installed temporary modifications (TMs) was
low and below the plant goal. The team concluded that the evaluation and control of
temporary modifications was good and that the installed TMs had no adverse impact on
safe plant operation.
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.The licensee had adequate controls in place to ensure deferred work was properly
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evaluated. No deferred modifications were identified that would affect safe plant
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operation.
The licensee had substantially improved the design and licensing basis of the control
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room heating ventilation and air conditioning (HVAC) system. Inconsistencies between
the system design criteria contained in the final safety analysis report (FSAR), TS and
the operating and surveillance procedures were eliminated. Single failure design errors
were corrected. The system readinesa review was thorough. The control room HVAC
surveillance testing program was a strength.'
E3
Enaineerina Procedures and Documentation
The operability (OD) process was comprehensive. Operability determinations were
technically sound and documented an adequate basis for establishing operability of the
- degraded component or system.
The licensee program to maintain the accuracy of vendor manual information was being
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properly implemented.
The licensee implemented an adequate setpoint process and the Millstone Unit 2
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Instrumentation and Control (l&C) setpoint specification provided a clear definition of the
program for the generation and documentation of safety-related, instrument and control
setpoints. In general, the setpoints selected for review by the team were properly
documented, reviewed, and supported by appropriate calculations.
The licensee implemented effective commercial grade dedication and item equivalency
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evaluation programs and performed appropriate evaluations to support plant restart.
The team concluded that the operating experience program was functioning adequately
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to support restart. The backlog of reviews had been evaluated by the licensee to identify
those issues requiring review before restart and appropriate priorities had been assigned
to these issues.
The majority of the drawing issues that have been identified over the past 12 months
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have had minor safety significance. Current procedures and processes for updating
operational critical drawings in the control room had been followed.
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Miscellaneous Enaineerina issues
The team concluded that the design changes resolved the emergency core cooling
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system (ECCS) single failure vulnerabilities. Additionally, the aspects of the design
changes reviewed, with the exception of the emergency operating procedures (EOP)
changes, had been properly implemented. The licensee demonstrated that appropriate
administrative controls were in place to ensure that the EOPs would be corrected prior to
- becoming effective. These findings provided the basis necessary for the closure of SIL
53.1.
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,.The licensee's corrective actions were considered appropriate to correct the issue
identified in licensee event report (LER) 97-34. The licensee's April 1998 pressure
locking tests indicated the valves would have remained operable and therefore the error
was of minor significance. However, the failure to use appropriate assumptions when
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initially analyzing the containment sump valves for susceptibility to pressure locking and
thermal binding (PLTB) was a weakness in design control. -These findings provided the
basis necessary for the closure of SIL ltem 20.7A and LER 50-336/97-034.
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Reoort Details
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The objective of the Operational Safety Team inspection (OSTI) was to provide current
information to the NRC Restart Assessment Panel by evaluating the readiness of plant
hardware, staff, and management programs to support a safe restart and continued operation of
Millstone Unit 2.~ The OST) observed operations at Unit 2 over a 17 day period; The OSTI
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(team) monitored licensee activities during plant transition between operational modes, both
during normal and off-normal working hours. The OSTI performed an independent, broad scope
assessment in the areas of management programs and oversight, operations, maintenance and
surveillance, and engineering and technical support. The OSTI used selected sections of NRC
Inspection Manual Procedure 93802, " Operational Safety Team inspection," to conduct this
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inspection activity.
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Management Processes
a.
Inspection Scope
The team reviewed records, procedures and performance measures and interviewed
licensee management and staff to determine the adequacy of the management team to
provide direction, standards, and expectations to the plant staff.
b.
Observations and Findinas
Standards and Expectations
The team reviewed the licensee's policies and instructions (e.g. Millstone Focus 99,
Northeast Utilities (NU) Nuclear Standards and Expectations, Operational Focus
Enhancement Plan, Nuclear Oversight Verification Plan) to assess the licensee's
success in establishing expected standards of performance. The team found that efforts
to raise performance standards were evident. Written safety standards were revised and
senior management conveyed expectations for meeting these standards by the
statements they made and the examples they set at meetings and during interfaces with
plant staff. Interviews with the plant staff indicated that established standards and
expectations were well understood and were generally being met.
Communications
Licensee management used a variety of methods to communicate and reinforce their
expectations for safe plant operation. For example, daily newsletters were published on
items of current interest, posters outlining management expectations for work activities
were prominently displayed, and both formal pre-planned and impromptu meetings were
conducted daily by individual line organizations and by line organization managers and
supervisors. The information in the daily pre-planned management meetings was
- presented by the Shift Managers with each key support department represented. Senior
management presence at these meetings was evident with their focus on goal setting
and ensuring expectations for safe plant operations was reiterated. The team observed
several meetings and found them well run, with the necessary personnel available to
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make key decisions in a timely manner. The team observed that management
expectations were further reinforced by discussing condition reports (CRs) and human
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performance errors during the management meetings. In addition to the management
meetings, each line organization had separate debriefs to discuss the issues raised at
the management meetings. During the debriefs they also reviewed scheduled activities,
discussed events and operating experience reviews where appropriate.
The probabilistic risk assessment (PRA) staff reviewed each proposed design change to
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ensure that it did not adversely impact plant risk. The PRA staff also established
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procedures for including risk insight into the schedule for on-line test and maintenance
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evolutions.
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Manaaement/Suoervisorv Oversiaht
Operations and maintenance management interfaced frequently with subordinates
through job-site tours and meetings. A Unit 2 Operations Department Work Observation
Program assured that operations department managers performed regular observations
of ongoing work. In addition, there was a structured management observation program
that required management and supervisory personnel to undertake plant tours and
report observations regarding staff working conditions and the material condition of the
plant. The team reviewed a sample of these reports and found that the findings from
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these reports were properly entered into the corrective action program and discussed
with the plant staff.
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Employee Concerns
The team conducted a random survey of plant staff to solicit their insights on the
Employee Concems Program. The team contacted approximately twenty individuals
from maintenance, operation, quality control (QC) staff, and engineering. All the
individuals interviewed indicated that they were aware of the program and had
confidence in the implementation of the process. This observation was consistent with
the findings of the recent NRC corrective actions inspection (NRC Inspection Report (IR)
50-336/99-01).
Staffina
The team verified that staff overtime was being controlled in accordance with Nuclear
Generation Procedure (NGP) 1.09, " Overtime Controls for all Personnel at Millstone
Station," and the NRC Policy Statement on working hours (NRC Generic Letter 82-12).
There were only three CRs written during the past 6-months regarding individuals
exceeding the overtime guidelines at Unit 2. The three cases involved an engineer
attempting to complete a task prior to vacation, a fire watch, and a technician. The
corrective actions for each CR were appropriate. The licensee's Performance
Evaluation group recently completed surveillance MP2-P-99-025, " Unit 2 Management
and Staff Overtime." The surveillance reviewed the overtime for several plant
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departments and used the security computer data to validate overtime hours. The
conclusion of this surveillance was that no personnel were identified exceeding overtime
. limits that would potentially present a safety hazard and that the line organization has
been proactive in the self identifying and correcting overtime limit violations. The team
noted that overtime controls were frequently discussed during department meetings and
plant staff interviewed were aware of the station overtime policy.
Restart Readiness Monitorina
The licensee's process for ensuring restart readiness was centered around the
implementation of the NOVP and the " windows" department readiness assessments.
These assessment techniques provided a useful measurement of plant restart
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readiness. The NOVP is the principle tool used by management to ensure the key
issues identified for restart are being satisfactorily accomplished. In addition to the
NOVP, each line organization used the " windows" readiness assessment tool to evaluate
- key performance criteria within their organizations. The input from these readiness
reviews was derived from the various self-assessments.
Nuclear Oversight reported on ten Unit 2-specific areas and six site-wide areas in the
March 1999 report to senior management. The areas of health physics, chemistry,
maintenance, work control / planning, corrective action, self-assessment, and fire
protection were all rated as satisfactory. Security and training were rated satisfactory for
the site. Operations, engineering, and procedure quality / adherence were rated as
- tracking to satisfactory for restart readiness. There was a plan for each area to make
these areas satisfactory and ready for restart. Emergency planning, environmental
monitoring, year 2000 computer issues (Y2K), and organizational realignment were not
satisfactory from a site perspective. Management's attention was properly focused on
the areas that need improvement.
Self-Assessments
The team evaluated the licensee's processes for performing self-assessments to ensure
that they were effective in identifying and addressing safety significant issues which
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could impact unit restart. The team reviewed a sample of line organization self-
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assessments and recent line management observations, witnessed management
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observations, and conducted interviews with cognizant staff. The recent NRC 40500
team inspection (NRC IR 50-336/99-01) also reviewed this area. The OSTI team
confirmed that the self-assessment process was functioning well. A wide variety of self-
assessment tools were in place and assessments were performed on a regular basis.
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Self-assessments were generally timely, appropriately critical of personnel performance,
and contained sufficient detail to be an effective tool for improving plant performance.
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. . . . .
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.
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4
c.
Conclusions'
Appropriate standards and expectations for safety were established by senior
management and were understood by subordinate managers and staff. The team
concluded that management expectations for safe plant operations were communicated,
understood and followed by the plant staff. Senior plant management used a variety of
communication methods to reinforce expectations. Management expectations regarding
employee concerns were understood by the staff.
Planning and direction for the restart and recovery of Unit 2 were effective. The
application of PRA insights to design and operation of the plant were appropriate.
Effective leadership was provided and management involvement in routine activities and
emerging issues was adequate. The NOVP and " windows" assessment tools were
effective mechanisms for management to assess restart readiness.
The team's findings, in addition to those of the NRC 40500 inspection team (NRC IR 50-
336/99-01), provide the basis for the closure of SIL item No.1, Management Oversight
,
and Effectiveness: Licensee Staff Safety Culture, and the associated NRC Restart
i
Assessment Plan items.
- S2
Corrective Action Program
a.
Inspection Scooe
The team conducted interviews and reviewed documents to assess the adequacy of the
corrective actions program. Two inspectors spent one week reviewing the Unit 2
updated submittal regarding the NRC 10 CFR 50.54(f) Information Request, dated March
5,1999. The team reviewed the " Items to be Completed After Restart" section of the
submittal to assess the licensee's process and basis in deferring items for completion
until after Unit 2 restart. In addition, the Unit 2 Restart Management Backlog Plan was
assessed for the integrated impact on the licensee's ability to both adequately prioritize
closure of the large number of open items and maintain focus on safe operation of the
unit post-restart.
b.
Observations and Findinas
Problem Identification Processg3
The corrective actions program has a low threshold for condition report (CR)
identification and initiation. The average number of CR's submitted per month is
approximately 300,- The team noted that the plant staff were generally diligent in writing
CRs to document deficiencies identified during this inspection. The operators' threshold
for identifying deficiencies was generally good. The plant equipment operators (PEOs),
in particular, were observed identifying and correcting deficiencies in the plant. Those
problems that could not be immediately corrected were documented in either trouble
reports or condition reports (CRs).
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5
Root Cause Evaluations
The team reviewed a sample of root cause investigations conducted several years ago,
- six from late 1998cand three from the first quarter of 1999. -The reports demonstrated an
improving trend in_ quality. Historically, there were examples of narrowly focused root
causes, which led to marginally effective corrective actions. The root cause investigators
used a variety of techniques that were appropriate. The more recent examples provided
adequate detail, including figures and flow paths, so that the situation could be
i
understood. The corrective actions were well developed. A review of the status of the
'
corrective actions associated with the CRs indicated that the corrective actions are being
accomplished in a timely fashion.
l
CR Feedback Process
The corrective action process requires that the CR initiator be informed of the resolution
of the CR. The team contacted ten CR initiators to verify that the CR initiators were
informed of the corrective action for the issues they had identified. Of the ten
individuals, nine were informed and indicated that the feedback process was working
well. One individual could not recall being informed of the corrective actions
implemented. One individual contacted implied that the corrective actions implemented
were not fully satisfactory; however, in this case, the CR indicated that the disposition
was accepted by the individual's supervisor.
Deferred Items Review
On March 5,1999, the licensee provided the latest update submittal to the 10 CFR 50.54(f)information request of April 16,1997. Specifically, the submittal contained the
" Items to be Completed After Restart" list, which consisted of items that the licensee had
' determined to be def.errable until after Unit 2 restart. This latest submittal was comprised
'
of items that had been.added by the licensee since the previous submittal of December
1998, which was also reviewed by the NRC as documented .in NRC Inspection Report
50-336/98-06.
j
The team reviewed approximately 1700 items on the deferred items list, and focused on
items based on safety significance, operability, or other issues such as the impact on
- design or licensing basis. The team subsequently selected approximately 100 of the
1700 items for further review, such that an adequate assessment of the licensee's
deferment could be made. The team also reviewed the methodology used by the
licensee to defer items post-restart and determined that the process adequately
identified items that were appropriate for deferral. The process was improved based on
lessons leamed from Unit 3, as well as from effectiveness reviews from the licensee's
corrective action program. The new process clarified operability questions relative to the
appropriateness of deferral or completion prior to restart. The new process also
established administrative requirements for addressing licensing or design basis issues,
. such as the need for specific license amendments, prior to restart.
-;
4
6
Based upon the review of the selected items, the team determined that the licensee's
deferral of the items was appropriate. However, in several instances, the licensee had
provided weak documentation reg ? iing the basis for deferral. While the licensee's
'
process required, in part, that the ">stification must be a stand alone explanation," such
that the justification would be very clear and provide enough information for NRC review,
the team found that the justification for deferral provided by the licensee was not always
sufficient to afford an independent conclusion that supported deferral of the item. In all
cases, the licensee provided the necessary information or documentation to support their
i
decision for deferral of the items.
I
in addition to the specific deferred items inspection, OSTI team members supplemented
this inspection effort with a review of approximately 15 EWRs that had been deferred.
The EWRs deferraljustifications were all appropriate.
Backloa Manaaement
On December 22,1998, the licensee submitted the Restart Backlog Management Plan
~ to the NRC. The licensee's plan provides for an integrated, structured approach to
manage and disposition the backlog of identified items at the time of Unit 2 restart. In
addition, the plan also attempts to balance the closure of the identified items with the
need to focus on safe, event-free plant operations. Through December 18,1998, the
licensee's identified backlog consisted of 2765 deferred items. The licensee has
established specific dates for completion of these items.
The team noted that the licensee plans to develop guidance for the backlog
management plan, which will reflect the following functional requirements:
The disposition of unresolved item reports (UIRs), independent Corrective Action
Verification Program (ICAVP) discrepancy reports (DRs), and the remaining
recovery ba :klog items (described previously as '* deferred items").
Existing work control processes will be used to disposition the items.
Performance monitoring will be established, tracked, and monitored 'or the
backlog plan; key performance Indicators (KPis) will also be reported quarterly.
Management will conduct performance reviews of the KPl goals. In addition,
.
periodic assessments will be conducted to ensure management stcr.dards
continue to be conservatively applied.
i
On March 30,1999, the licensee submitted a change to the Backlog Management Plan
commitments for both Units 2 & 3. Specifically, the licensee's timetable for completion of
ICAVP DRs for Unit 2, was changed from prior to entry into Mode 2 following the
completion of the next refueling outage, to an expected completion date of December 31,
,
2001. This commitment schedule change was made based on lessons learned from
'
Unit 3. The basis for this change appears to be appropriate, given the licensee's efforts
1
in the assessment of both +he safety significance of the items that have been deferred,
as well as the overall impact the backlog management plan would have on the continued
safe, event-free operation after restart.
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7
c.
Conclusions
l
The overall corrective action program is adequate to support plant restart. Plant
deficiencies are being included in the corrective action program and recent root cause
l
evaluations are thorough.
The team concluded that the licensee's backlog management plan was adequate. In
l
addition, the NRC concluded that the licensee's process for deferral contained
l
appropriate methodology for the identification of items acceptable for deferral and
completion after the Unit 2 restart. Moreover, the team did not identify any items that if
i
,
not completed prior to restart, would have an adverse impact on the safe restart of Unit
2.
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The team's findings, in addition to those of the NRC 40500 inspection team (NRC IR 50-
336/99-01), provide the basis for the closure of SIL items No.12, Licensee Restart
Punch List - Review Items Deferred Until After Restart, and the associated NRC Restart
Assessment Plan items.
!
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S3
Independent Oversight
!
a.
Inspection Scope
!
The team reviewed procedures goveming audits, surveillances and the Nuclear
- Oversight Verification Plan (NOVP) process, reviewed NRC inspection reports, observed
a NOVP Panel meeting, and interviewed licensee representatives to assess the
effectiveness of independent oversight provided by the Nuclear Oversight Organization.
Nuclear Oversight audit findings were reviewed to verify that significant audit findings,
with potential unit restart implications, had been resolved.
b.
Observations and Findinas
Performance associated with each of several key issues was evaluated and documented
in oversight evaluation reports using a method that provided for measurement
consistency. Data from oversight evaluation reports were assessed using
predetermined acceptance criteria and the results were provided to senior management
in monthly reports. Evaluations were made objectively and the results were consistent
with NRC inspection findings. Evaluation reports were communicated orally to the line
,
organization to provido prompt feedback and then complemented with periodic written
reports.
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8
Throughout the NOVP process, the Nuclear Oversight Organization provided valuable
independent feedback to station management on the status and quality of operations,
maintenance, surveillance and engineering restart activities. The audit program is
aggressive in breadth and scope and achieved its targeted number of audits in 1998.
Audits by Nuclear Oversight provided comprehensive assessments in selected
i
programmatic areas. They produced performance-based findings that were of value for
'
improving program effectiveness. Surveillances were typically performance-based and
identified opportunities for improvement.
Line managers from operations, maintenance, and engineering respect the role of
' Nuclear Oversight and value their input as opportunities for improvement. They actively
participate in audit exit meetings and NOVP Panel meetings. Good interaction between
Nuclear Oversight and line managers was apparent.
The team reviewed two stop work orders issued by Nuclear Oversight. While neither of.
j
the issues had a significant adverse effect on plant safety, the fact Nuclear Oversight
was empowered to issue the orders, and was supported by senior management,
indicates a healthy oversight function.
The team reviewed findings from Nuclear Oversight audits and other reviews. The
response to findings was timely and the team determined that findings with potential
restart implications had been properly dispositioned.
The licensee assesses the effectiveness of Nuclear Oversight by using a variety of
independent groups such as the Joint Utility Management Assessment (JUMA), Institute
of Nuclear Power Operators (INPO), and/or independent assessment teams. The OSTI
team reviewed the JUMA report and that of the independent assessment team. The
audit findings were clear, objective and appropriately included in the corrective action
process.
c.
Conclusion
The NOVP provides effective independent assessment of performance for resolution of
" key issues." The Nuclear Oversight Organization's involvement in operations,
maintenance, surveillance and engineering has been satisfactory. Line organization
cooperation and support for oversight activities was apparent. The team concluded that
the various reporting mechanisms employed by the nuclear oversight organization
provided an ef'ective means of capturing conditions adverse to quality and ensuring that
those conditions were corrected. The reports were critical assessments and provided
senior management with a useful" snapshot" of plant performance and areas requiring
additional attention. Nuclear oversight audit findings with restart implications are being
properly addressed.
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9
S4
Quality Review Committees
a.
Inspection Scooe
The effectiveness of oversight provided by the Plant Operations Review Committee
'
(PORC), Station Operations Review Committee (SORC) and Nuclear Safety
Assessment Board (NSAB) was reviewed. The team observed meetings, reviewed
meeting minutes and interviewed cognizant personnel,
b.
Observations and Findinas
,
Plant Operations Review Committee
The team observed several PORC meetings and verified that the PORC meetings
comply with TS and the members were capable of conducting TS required reviews. The
PORC members were reasonably well prepared for the issues on the agenda and asked
pertinent and challenging technical questions of the presenters and each other. The
PORC meetings were conducted in a professional manner.
Meeting minutes are distributed in a timely manner and contain information from the
presenters. However, the team noted that the meeting minutes did not always provide
sufficient detail to determine how PORC member concerns were addressed. For
example, in meeting minutes 2-99-051, the Chairperson requested that an individual
making a presentation to PORC ask licensing to provide the reason for a note in the
procedure being presented. The meeting minutes do not reflect the importance of this
request or how licensing was expected to respond to PORC.
Site Ooeration Review Committee
The SORC members were well prepared for the items on the meeting agenda and asked
technical questions of the presenters. ' Walk-in" items (i.e., items which are not pre-
distributed to the members) were discouraged. One " walk-in" item at the observed
i
meeting was rejected because of a concem of a member which could not be addressed
at the time by the presenter. The members adequately represent the site-wide
perspective of the SORC. The SORC meets weekly rather that the TS minimum of once
every six months. This maintains the agenda manageable, the meetings reasonably
short, and issues current. The team reviewed the SORC backlog items and verified that
there was no potential restart issues at the time of the inspection.
Nuclear Safety Assessment Board
The team evaluated the effectiveness of the NSAB to provide independent oversight to
the organization. The team verified that the NSAB met the requirements of the TS.
Procedures and processes are in place to ensure continued compliance with TS.
Subcommittees are effectively used to relieve the full NSAB of detailed paper reviews
and allows it to maintain a broader perspective.
,
-
,
.
10
' independent members, including the Chairman, provided in-depth and probing questions
and observations. They also provide mentoring to the subcommittees. Members of the
NSAB, who are employees of the licensee, are senior managers and effectively remove
themselves from the line management role for their roles as independent oversight on
the NSAB. The NSAB meeting minutes are reasonably timely and thorough.
c.
Conclusion
The PORC, SORC and NSAB all meet the TS requirements. At the time of this
inspection, there were no outstanding oversight committee items that would adversely
affect unit restart. The team concluded that the NSAB was providing effective
,
independent oversight.
Startup Plans
a.
Inspection Scope
The team reviewed the Operational Readiness Plan, special procedure (SPROC) OP98-
2-08, " Unit 2 Restait Following 10CFR50.54(f) Outage," and supporting documents. The
team also assessed the effectiveness of the startup and power ascension organization
oversight during unit heatup activities. This review was accomplished through
observations, interviews, and documentation review.
b.
Observations and Findinas
,
The Operational Readiness Plan (ORP) addresses those aspects of unit operation that
provided the basis for the unit shutdown in 1996. Appropriate restart goals were
identified in the ORP as key issues. Each key issue had an assigned manager
responsible for monitoring it's resolution. Interviews with the key issue managers
indicated that the assigned individuals were aware of their responsibilities and issue
status. The ORP considers the organization, system readiness, operational readiness,
regulatory readiness, and communications. The team verified that appropriate aspects
i
of the plan had been completed. The Nuclear Oversight Verification Plan (NOVP) was
i
independently assessing performance in each key area on a biweekly basis.
~ Management effectively used this process to focus attention in areas needing
improvement for restart.
SPROC OP98-2-08 provides adequate hold-points for operations and unit management
to control unit restart. The procedure appropriately required input from line
organizations, oversight, and PORC. _ Appropriate independent oversight of restart
activities was included in this procedure.
.
11
c.
Conclusign
The team concluded that the licensee had developed detailed resta i plans and
established an augmented oversight organization for unit startup.
j
ll. Operatiorg
Backaround & Plant Status
,
At the start of the OSTI, Unit 2 was in cold shutdown (Mode 5). On March 25,1999, the
plant entered hot shutdown (Mode 4) and on March 31,1999, the plant entered hot
standby (Mode 3). The team observed operations activities during both mode changes.
The team's observations were performed over a 17 day period that included over 110
hours of shift observation including backshift and weekends. The team's findings '
documented in this report provide the basis for the closure of SIL item No.13, Operator
Performance, and the associated NRC Restart Assessment Plan items.
01
Conduct of Operations
'
a.
Inspection Scope
The team assessed the adequacy of overtime controls, shift turnovers, and pre-job
briefs.
b.
Observations and Findinas
Overtime Controls
The team reviewed operator time and attendance records from January 1 through March
22,1999. The team noted that working overtime was routine but operators rarely worked
overtime beyond established administrative limits. The limits for overtime were defined
'
in Nuclear Group Procedure (NGP) 1.09, " Overtime Controls for All Personnel at
Millstone Station."In a few instances where overtime limits were exceeded, prior
management approval was properly obtained and documented.
Operating crews worked on average about 12 to 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of overtime each work week.
During interviews shift managers and their crews described many of their crew members
as being tired; however, the team did not identify any operator fatigue related issues
during the inspection. The licensee planned to transition back to a five-crew shift
rotation, that provides operators more time off than the current four-crew shift rotation,
prior to the plant startup.
.
-
12
Shift Turnoven
The team observed fifteen (15) shift relief and turnovers. The turnovers were of good
quality, in that necessary information concerning plant systems status was discussed
and understood by the oncoming shift. It was noted that each member of the control
room staff walked the main control room boards with their relief and discussed plant
status. A shift turnover briefing for the oncoming shift was held after the individual
operators had completed their station turnovers. During the briefing, each individual
gave an update on activities related to their station. Active participation in the shift
turnover by support groups to operations (work control, maintenance, chemistry, health
physics, security, etc.) was evident. The Shift Technical Advisor routinely provided
adequate risk insights during shift turnover. The shift relief and turnovers observed were
conducted in accordance with the instructions delineated in procedure U2 OP 200.1,
" Unit 2 Conduct of Operations."
A recent self-assessment report identified that the shift turnover report did not evaluate
alternative plant configurations relative to 10 CFR 50.59 safety evaluation screens.
Team review of various shift turnover reports did not identify alternative plant
configurations for which a safety evaluation screen was necessary.
Pre-Job Briefs
The team observed several pre-job briefings and found that they were generally detailed
and thorough. There were detailed discussions en responsibilities, precautions,
expected plant conditions, contingencies, and a strong emphasis on plant safety and
taking the time to do the evolutions correctly. The plant briefings for the transition from
Mode 5 and Mode 4 and for SPROC EN98-2-23, " Operational Testing of 2-SI-651 (DCR
M2-98055), IPTE," that temporarily removed shutdown cooling from operation, were
performed well with good participation by the system engineers. During the plant heat-
up briefing, good insights were provided on reactor coolant pump performance and
expected motor vibration values.
The team also observed the shift brief in preparation for the Mode 3 transition, and
considered this brief adequate. The control room briefincluded appropriate guidance
regarding termination of the heatup based on increased leakage from the 2-SI-652 valve
.
(inboard shutdown cooling isolation valve), and the safety injection tank valve leakage;
however, the team noted that no specific valve leakage limits were established (i.e., if
the leakage from the reactor coolant system gets worse). Notwithstanding this lack of
specificity on termination of the heatup, operators were sensitive to the known leakage.
Precautions and limitations from OP-2201, " Plant Heatup," were adequately discussed.
During observations of a pre-evolution briefing for procedure SP 2610A, " Auxiliary
Feedwater Test," misinformation was provided to the plant equipment operator (PEO) on
the position of the atmospheric dump valve to be operated. The PEO appropriately
notified and corrected the communication error prior to manipulation of the atmospheric
dump valve.
.
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13
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-c.
- Conclusion
The operations department had sufficient personnel to provide coverage throughout the
restart period without excessive use of overtime. The shift tumovers observed were of
high quality with active participation from groups supporting operations. Pre-job briefings
were generally good with a few minor communications weaknesses.
02
Operational Status of Facilities and Equipment
a.
Inspection Scooe
The team assessed plant configuration controls by reviewing system equipment
alignments, conducting system walkdowns, and reviewing the equipment tagging
process and the locked valve program.
b.
Observations and Findinas
i
Review of Valve and Breaker Lineuos
The team reviewed completed valve and breaker lineups that the licensee had
performed to support plant heatup, observed operations personnel retuming selected
portions of systems to service (i.e., reactor coolant, auxiliary feedwater, and emergency
diesel genemtor starting air), and observed operations personnel perform independent
verifications of these activities. The team also reviewed the PEO training guides and
determined that the operators had been adequately trained and were qualified to perform
valve lineups and independent verifications.
. The team did not identify any problems with the valve and breaker lineups, the process
for retuming systems to service, independent verifications, or qualification of valve
alignment personnel. However, during the OSTI and the month prior to the OSTI, the
licensee issued several condition reports which documented problems with the
i
implementation of activities related to the valve and breaker lineup processes (See the
documents reviewed section of this report for examples).
These CRs documented instances of inadequate valve lineup restoration and inadequate
valve lineups. The inadequate valve lineups were either valves added by modifications
that did not get incorporated in all required lineups and documents, or discrepancies
between valve lineups and drawings, and/or procedure changes that did not get
incorporated into the valve lineup. The licensee was evaluating the problems
documented in these condition rep 3rts to determine their causes and corrective actions.
These valve lineup deficiencies were either licensee identified or self identifying. There
were no safety consequences as a result of these deficiencies. Therefore, the failure to
follow procedures as related to these events was of minor safety significance and is not
subject to formal enforcement action.
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14
System Walkdowns
The team performed reviews of system valve lineup sheets and piping and instrumert
drawing (P&lDs), and also performed walkdowns of selected portions of the auxiliary
feedwater, service water, reactor building closed cooling water, and the 4.16 kilovolt
systems. During the reviews and walkdowns, the team verified that: system lineup
procedure requirements matched plant drawings and as-built configuration; valves in the
flow path were in the correct positions; electrical breakers were properly aligned; and the
condition of the components and equipment observed was acceptable. The team did not
identify deficiencies with plant drawings, valve alignments, or condition of components.
Eauioment Taaaina Proaram
The team randomly selected equipment isolation and control tags hung in the plant and
verified that the information on each of the tags agreed with information on the clearance
sheet, the tag was installed on the correct component, and the component was aligned
correctly. The team also selected and walked down active equipment clearances and
verified that the information on the clearance and tags agreed, tags required by each of
the clearances was on the correct component, and the component was in the correct
position. Additionally, the team observed an operator implement tagout 2-0650-99 to
isolate the "A" high pressure safety injection pump seal cooier. The tagout was
appropriately applied. The clearance /tagout process appeared to provide adequate
controls to ensure personnel safety and plant configuration. However, several CRs
. documented recent tagging and maintenance problems indicating that implementation of
the tagging program has not been fully effective. The licensee was evaluating these
problems to determine their causes and corrective actions at the end of the inspection.
Locked Valve Proaram
The team randomly selected locked valves in various safety systems and vent and drain
valves associated with containment integrity. The team verified that the valves were
locked in the position required by the locked valve lineup list. One minor instance
existed where two integrated leak rate test valves (2-AC-113 and 2-AC-115) outside the
containment boundary were locked and not reflected within 2-OPS-1.32, " Locked Valve
,
Checklist." The licensee processed a locked valve evaluation form to add these two
valves to the locked valve checklist.
c.
Conclusion
i
The implementation of processes to establish and maintain configuration control were
i
generally acceptable. However, various condition reports identified problems in the
- valve lineup and tagout process that indicate implementation was not always effective.
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03
Operations Procedures and Documentation
a.
Inspections Scope
The team reviewed selected plant and system operating procedures; observed
operators' implementation of procedures; assessed temporary procedure changes; and
assessed whether risk significant operator actions had been adequately proceduralized.
b.
Observations and Findinas
Procedure Quality
The quality of operating and administrative procedures were generally good. The
. procedures reviewed were technically accurate and provided an appropriate level of
detail.
Most operations procedures had been recently revised as part of a procedure upgrade
program (PUP). Since April 1998, approximately 60 technical procedures had been
upgraded by the PUP that included verification and validation of the procedures,. The
team noted that the revised procedures appropriately followed the procedure writer's
guide. There were only three operations procedures which had not been upgraded.
These were scheduled to be completed in May 1999.
On March 31,1999, the team observed that e.a Unit Supervisor (US) had marked up
copies of SP 2606B, " Containment Spray Operability /IST Facility 2" after completion of
the surveillance. The surveillance procedure had incorrect information on the position of
the recirculation valve for the "B" containment spray pump. The team confirmed that a
procedure change was being processed and that actions to complete the surveillance
were consistent with the guidance in DC-4, " Procedural Compliance."
The quality of plant heatup procedure OP-2201 was good. This conclusion was based
- upon the team's observation of operators using the procedure during plant heatup. The
procedural actions and implementation were conducted well during the transition
between shutdown cooling and using the steam generators as the heat sink. The
transition resulted in very little variation in both reactor coolant system temperature and
pressure.
.
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16
)
The team noted that a surveillance test procedure deficiency resulted in declaring the "C"
service water pump inoperable A recent procedure revision had added a second pump
,
performance curve from the f@afety analysis report (FSAR). However, the FSAR
_ pump curve did not account for instrument inaccuracies and suction pressure variations
due to sea level elevation changes. This omission resulted in the surveillance test
failure. Short-term corrective actions were to perform a safety screen, remove the FSAR
. figure from the procedure and provide clarification on performance curve differences in
the procedure. Team review of the pump performance data concluded that the pump did
not degrade into an unacceptable range.
The licensee identified ten significant operator actions that had a measurable impact on
core damage frequency, The team verified that the licensee had appropriately
proceduralized these operator actions in the appropriate emergency and abnormal
operating procedures.
The team reviewed various emergency operating procedures (EOPs) and abnormal
operating procedures (AOPs) to confirm proper labeling and equipment staging for
operator actions outside and within the control room. The review consisted of in-plant
validations, simulator validations, and reviews within the control room. The evolutions
involved local control of the auxiliary feedwater turbir!e, energizing the 4.16 KV bus 24E
from unit 1 bus 14H, loss of all feedwater, local operation of the atmospheric dump valve,
cross connection of unit 1 station air, and supplying fire water to the auxiliary feedwater
pumps.
Generally, proper equipment was staged and appropriately identified on SP 2657,
" Emergency Operating Procedure Equipment Inventory." Components were generally
labeled appropriately and lighting in the area was appropriate. In one case, EOP 2537,
" Loss of All Feedwater," two control room panel designations for operator actions were
incorrect, and contingency step 2.20.c contained a human factor deficiency between the
expected action and labeling on control panel COS. On March 23,1999, the licensee
generated a CR to document these deficiencies.
The team verified that local operation of plant equipment had been tested and operator
actions were validated. The team confirmed periodic testing to locally cycle the
atmospheric dump valves (2-MS-190A and B) and the fire water supply valves to the
auxiliary feedwater pumps existed in surveillance procedures. Several, minor validation
issues were identified by the team that included: no area temperature indications for the
auxiliary feedwater room, no validation of local operation of the atmospheric dump valves
with operators using self-contained breathing apparatus, and no performance testing to
'
+
confirm acceptable reactor building component cooling water flow to the instrument air
compressor. These minor validation issues were resolved by either the licensee
validating actions or providing additional information to substantiate that the existing
procedures were technically acceptable.
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17
Procedure Adherence
i
The team observed implementation of numerous operating procedures and surveillance
~
activities that included procedures for starting reactor coolant pumps, securing the
residual heat removal (RHR) system, controlling plant heatup from Mode 4 to Mode 3,
filling the safety injection tanks, and control element assembly testing. The team noted
appropriate procedure implementation as required in DC 4, " Procedural Compliance."
.
c.
Conclusions
Operator procedural quality was generally good. Some minor validation deficiencies
were noted in a few surveillance and emergency operating procedures; however, none
had an impact on safe operation of the facility. Appropriate procedural adherence by
.
operators was observed.
04
Operator Knowledge and Performance
a.
Insoection Scope
The inspection scope consisted of observations of operators both inside and outside the
control room. The observations included changes in plant conditions, surveillance
testing, or other activities that demonstrate the abilities and knowledge of operators. The
team also verified that log-keeping practices were adequate.
b.
Observations and Findinas
Ooerator Performance
Operator performance was generally good during the periods of team observations.
General control room demeanor was observed to be appropriate. Both licensed and
non-licensed operators were aware of plant conditions and maintenance activities in
progress. The observed evolutions were well controlled with appropriate supervisory
{
oversight. The operators conducted plant evolutions in a safe and controlled manner,
'
and exhibited a conservative approach to equipment manipulation.
The team accompanied several plant equipment operators (PEOs) on their rounds. The
team observed that the PEOs properly performed their rounds, properly filled out their
log sheets and out-of-specification readings were documented and resolved. The team's
observations of PEOs performing activities within the auxiliary building identified
appropriate identification of issues such as leakage from a post-accident sample system
(PASS) filter, waste gas compressor relief valve leakage, and leakage from the "B" high
pressure safety injection (HPSI) inboard seal cooler.
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Shift Technical Advisors were knowledgeable of plant risk evaluations. Plant evolutions
that resulted in changes to the risk assessment were properly discussed during shift
tumovers.
The unit supervisor (US) appropriately consulted technical specifications during
interactions with surveillance test personnel to confirm adherence to appropriate
compensatory measures. Plant activities involving makeup of soluble boron to the
volume control tank included multiple checks to ensure adherence to reactivity
management practices. The team's review of past events indicates that several
reactivity management issues had occurred between November 1998 and January 1999.
An adverse trend CR was appropriately initiated on March 1,1999 to evaluate common
cause attributes of these past events. This issue is described in the NRC's Resident
inspector inspection report (NRC IR 99-02).
!
Loa Keepina
Operator log keeping was adequate and performed in accordance with procedure U2 OP
. 200.1, " Unit 2 Conduct of Operations." An electronic log (the shift manager's log) was
maintained by the control room staff to document shift activities. This electronic log was
readily available to the plant staff. Information logged in the shift manager's log included
limiting condition for operation (LCO) entries and exits, the starting and stopping of major
n
plant equipment, unanticipated events (i.e., equipment failure) and the completion of
surveillance tests.
Self Checkina and Con' trol Board Awareness -
Generally, control board awareness and annunciator response were good. However, on
several occasions, the team observed that operators failed to communicate unexpected -
alarms to the US. No adverse consequences were observed due to this lack of
communication and the team noted improved communication regarding unexpected
alarms during the duration of this inspection. When unexpected alarms annunciated,
the control room operators reviewed the correct alarm response procedure and took
appropriate actions. The practices of self checking and peer checking were frequently
implemented by the operators.
j
The team found that operations management was actively involved in operations
activities. The team frequently observed operations management in the control room
providing guidance to the shift. Operations management participated in shift tumover
meetings to reinforce expectations.
Generally, control room operator's expeditiously identified plant equipment malfunctions
or changes in plant conditions. Examples included timely awareness of reactor coolant
systerp (RCS) inventory loss (0.3% indicated pressurizer level change) during an
!
evolution to drain portions of the letdown system in support of local leak rate testing.
)
However, in one case, a unit supervisor failed to recognize the need to conduct a
!
technical specification required surveillance test. Specifically, when RCS pressure was
raised above 200 pounds per square inch absolute (psia), in support of SP 21199, "LPSI
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System and Shutdown Cooling Heat Exchangers Leakage Test," no control existed to
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Implement technical specification surveillance requirement 4.7.2.1. The surveillance
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requires that every hour the steam generator primary and secondary temperatures be
-verified to be greater than 70 degrees Fahrenheit (*F). The team confirmed that
temperatures were always greater than 70 "F during the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that the surveillance
was not performed. The licensee prepared CR M2-99-1060 to document this missed
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surveillance and was in the process of preparing a licensee event report at the end of the
inspection. The team reviewed other condition-based surveillance requirements to verify
that adequate procedures existed to conduct the surveillances and no deficiencies were
,
identified. The failure to conduct the required TS surveillance test is a severity level IV
violation and le being treated as a non-cited violation, consistent with Appendix C of the
NRC Enforcement Policy (NCV 50-336/99-004-01)
c.
Conclusions
Operator performance was generally good and control room demeanor was observed as
appropriate. Both licensed and non-licensed operators were aware of plant conditions
and maintenance activities in progress.
The operators conducted plant evolutions in a safe and controlled manner, and exhibited
a conservative approach to equipment manipulation. Generally, control room operators
expeditiously identified plant equipment malfunctions or changes in plant conditions.
,
However, in one case a technical specification surveillance test requirement, to monitor
)
steam generator temperatures, was not performed in a timely manner. There were no
safety consequences as a result of not conducting this surveillance because the required
plant parameters were always satisfied. The failure to conduct this technical
specification required surveillance is a violation of NRC requirements. This Severity
Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of
the NRC Enforcement Policy. This violation is in the licensee's corrective action program
as Condition Report M2-99-1060.
Generally, operator control board awareness and annunciator response were good.
However, on several occasions, the team observed operators fail to appropriately
communicate unexpected alarms to the Unit Supervisor.
05
Operator Training and Qualifications
a.
Inspection Scope
The team observed operator training and examined qualifications records to verify that
required training was complete and training records were properly maintained.
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b. '
Observations and Findinas
Reaualification Trainina
The team observed a portion of licensed operator requalification training and reviewed
licensed operator requalification training records to verify that all required training was
performed. The team specifically verified that licensed operators attended and passed
requalification training for the plant startup procedures. The team reviewed lesson plans
and simuiator scenarios and found both to be satisfactory. Management involvement
was evident from comments in simulator evaluation records. The team found that
operators returning to shift from administrative or other assignments satisfactorily
,
regained licensed duty proficiency.
Restart Trainina
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A review of the lesson plans for restart instruction indicated that the training was
'
adequate. Training for entering Mode 4, and the subsequent plant heatup, occurred
early this year.
One licensed operator candidate had not performed the required number of reactivity
manipulations prior to the shutdown in early _1996. The qualification card for this
individual clearly documented the need to perform the required manipulations in order to
complete the requirements for his license.
Modification and Simulator Trainina
The team evaluated specialized classroom and simulator training to verify that the
. operators were adequately prepared for a safe plant restart. Additionally, the team
discussed recently installed plant modifications with several operations personnel. The
personnel interviewed were knowledgeable of the modifications completed during the
extended outage, and the effects on the plant systems and procedures.
1
- The team observed portions of operator training provided on plant modifications and
4
witnessed control room simulator training. Lesson plans for classroom instruction were
adequate to ensure that the operators were cognizant of the plant modifications. Plant
l
operators stated that management was present for classroom instruction and
participated by toenforcing goals and operating policies. During the conduct of simulator
training scenarios, the SM and US appropriately monitored and directed crew activities.
.Overall, the operators demonstrated good knowledge of plant systems and
modifications, and effective use of the operating and emergency operating procedures.
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.c.
Conclusions
l
All licent.e4 >perators had satisfactorily completed requalification training, A review of
the lessc:, plans, discussions with licensed operators, and observation of plant and
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simulator performance indicated that the training provided to the operators was sufficient
1
to ensure that they could safely restart the unit. Modification training for the operators
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was appropriate to effectively communicate plant changes completed during the outage.
06
Operations Organization and Administration
a.-
Insoection Scope
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The team assessed operator communications within the control room, verified adequate
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shift staffing, and verified that plant management were providing adequate oversight.
b.
Qbap_ntations and Findinas
Staffina Levels
)
The team reviewed the operations department staffing levels. There were five operating
crews. During the inspection, four crews were on shift rotation operating the plant and
one crew was assigned to the work control center. Each operating shift had two licensed
senior reactor operators, two licensed reactor operators (COs) and at least two plant .
equipment operators (PEOs) and a STA. During complex evolutions or evolutions which
.
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had not been recently performed (i.e. plant heatup), additional operators supplemented
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the control room staff to assist and to perform peer checks. The team found that
operations department staffing levels were adequate to support the safe operation of the
plant and minimum shift complements were always met.
Communications
The team observed communications on all shifts among operators and between the
1
control room and other site organizations were generally good. Management
expectations regarding three way oral communications were generally met.
in general, the team observed that the SM and US were effective in identifying issues
that required operability determinations (OD). However, the team noted one isolated
case where an OD for the station batteries was not initiated in a timely manner. On
March 17,1999, the assistant operations manager (AOM) briefed the operators on a
station battery performance issue. An OD for the station batteries was not initiated until
after the team discussed the need for an OD with shift management. In response, the
licensee appropriate ( prepared operability determination MP2-022-99, on
March 20,1999, and concluded that the station batteries were operable with
compensatory measures. The team reviewed the operability determination and
associated procedure changes and found them acceptable.
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Suoervisorv Oversiaht
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The team found that the quality of command and control of shift activities was good.
The US and SM were knowledgeable of and frequently involved in ongoing plant
!
activities.
c.
Conclusions
Operations department staffing levels were adequate to support the safe operation of the
plant. Communications within the operations department and with other site
organizations were good. Operators generally initiated operability determinations in
response to degraded equipment conditions. The team observed good command and
control of shift activities.
07
Quality Assurance in Operations
i
a. -
Insoection Scope
The inspection scope consisted of reviews of recent oversight and self-assessment
reports, performance indicators, and corrective actions for issues identified in the
assessments,
b.
Observations and Findinos
Oversiaht and Self-Assessment Functions
During the team's assessment, the licensee had continuous nuclear oversight of
operations activities and a peer evaluation during the week of March 15,1999.
The team reviewed nuclear oversight log entries for the two week inspection period.
Nuclear oversight observations provided an accurate account of activities involving the
conduct of operations. Some of the observations such as missing pages in surveillance
procedures, inconsistent quality of three way communications, and difficulty in evaluating
valve alignment completions were generally consistent with the OSTI findings.
The team observed one example where a nuclear oversight observer inadvertently
changed a plant process computer display being used by operators to monitor reactor
coolant pump net positive suction head. The STA immediately restored the display,
verified that plant conditions did not change in the short time period the display was
affected, and spoke with the nuclear oversight person regarding changing parameters on
the computer. The licensee initiated CR M2-99-1246 to evaluate corrective actions for
this event.
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The team observed a debriefing between the peer evaluator from Seabrook Station and
the operations manager on March 20,1999. The peer evaluator observed the conduct
of operations during the week of March 15,1999. The review was objective and
-identified areas for improvement that included inconsistency in crew communications,
opportunities for debrief of special evolutions to enhance lessons leamed, and improved
knowledge of operability determinations by SMs. The operations manager was in the
process of evaluating improvements at the end of the inspection period.
The team reviewed the operations self-assessment program as described in OA-11,
"Self Assessment," and the results of the program between February 22,1999, through
March 5,1999. Twenty areas wers the focus of the self-assessments. Areas identified
j
as needing improvement were worker practices, awareness of plant status, tagging, and
operator burdens. The one area that did not meet management's expectations involved
several valve mis-positioning events. The five areas either needing improvement or not
I
meeting management's expectations all had corrective action plans.
i
The team reviewed self-assessment 2 OPS-SA-99-18, " Millstone Unit 3 OSTl Lessons
Leamed." The assessment evaluated fifty-six areas to confirm unit 2 readiness for
restart. The assessment was thorough and deficiencies were appropriately entered into
J
the corrective action program. _ The team reviewed condition reports written as a result of
this assessment and concluded appropriate corrective actions had been established.
Some of the outstanding condition reports included increasing the resources to approve
and schedule maintenance activities, improvements in post-evolution debriefs, and
increase in awareness of operating experience information. The teams' assessment
indicated actions were being taken to resolve the issues.
The team reviewed follow-up actions associated with self-assessment report 2 OPS-SA-
99-18A, conceming three configuration control events documented in NRC Inspection
- Report 50-336/99-02. The causal factors for the events involved lack of management
,
control of on-shift work load, less than adequate resources, and insufficient on-shift
personnel to control plant status. The teams observations indicated improvements in the
areas needing corrective actions.
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c.
Conclusions
Nuclear oversight observations provided accurate accounts of activities involving the
conduct of operations. Self-assessments were critical and the licensee's corrective
action plans for improvement were appropriate.
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Ill. Maintenance and Surveillance
M1
Conduct of Maintenance
M1.1 Observations of Maintenance and Surveillance Activities
a.-
Insoection Scope
The team observed maintenance and testing activities to assess the overall quality of the
maintenance and surveillance testing programs. The team verified that pre-job briefings
were thorough, mechanics and test personnel followed procedures, and management
oversight of field activities was appropriate. The team also reviewed the post
maintenance test failure rate and the maintenance rework rate to assess the quality of
maintenance.
b.
Observations and Findinas
Reactor Buildina Closed Coolina Water (RBCCW) Heat Exchanaer Flow Test
The purpose of this test was to verify adequate service water flow through the RBCCW
heat exchangers during an accident. The pre-job briefing was thorough, coordination
with the control room operators was good and engineering involvement was appropriate.
All equipment manipulations were directed by the control room and procedural
adherence was good. The test was postponed one day to implement necessary
procedure changes.
4
Enaineered Safeauards Actuation System Diode Replacement
The licensee identified that a non safety-grade diode had been inappropriately installed
in the engineered safeguards actuation system (ESAS). The diode replacement work
was coded as a Mode 4 hold, but due to difficulty identifying the correct part number, this
job was not included in the work schedule. The outage manager noted this discrepancy
i
and scheduled this task as emergent work to be performed one day before Mode 4 work
was planned to be completed. Poor planning resulted in this task becoming emergent
work. Plant conditions and questions regarding plant impact of this task by the US
,
resulted in this task being delayed one day. This activity'was an example of how
emergent work adversely impacted schedule adherence.
The instrument and controls technician performing the work was very experienced and
knowledgeable of the task being performed. The team verified that the technician was
qualified to perform work on this system. The pre-job briefing was thorough.
Coordination with the control room operators and the system engineer was excellent.
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Turbine-Driven Auxiliary Feedwater (TDAFW) Pumo Throttle Valve Linkaae
The team observed maintenance activities associated with the adjustment of the throttle
- linkage for the TDAFW Pump. During earlier maintenance activities involving
replacement of portions of the throttle valve and linkage, a maintenance mechanic had
questioned the acceptability of observed tolerances in the linkage connections. The
maintenance observed by the team involved consultation with the pump vendor's
representative to ensure that the throttle valve linkage was properly installed and
)
aligned. The maintenance staff appropriately conducted this activity; however,
'
purchasing delays in contracting the pump vendor support resulted in this activity not
being performed as originally scheduled.
I
Control Room Ventilation Preventive Maintenance
The team observed the performance of several preventive maintenance (PMs) activities.
1
Generally, PM activities observed were completed in accordance with procedures,
However, in one isolated case, during the performance of a semiannual PM to inspect
'
the control room air conditioning coils, procedures were not appropriately followed. The
mechanic performing this activity inadvertently opened the duct port on the wrong train of
control room air conditioning (CRAC) system. The mechanic failed to properly complete
and sign the component identification procedure step, requiring the worker to verify the
~ proper component prior to conducting the maintenance. This was contrary to the
conduct of maintenance administrative procedure that requires the verification sign-offs
- and self-checking be complete to ensure that the task was completed correctly. Upon
discovery that the PM had been initiated on the wrong train, work was immediately
stopped, the wrong train sealed, and work continued on the proper train. However,
maintenance supervision was not informed of the incident in a timely manner. The
conduct of maintenance administrative procedure also requires that, if unexpected
conditions develop, work shall be stopped, equipment or systems be placed in a safe
condition, and supervision be informed. The licensee appropriately determined that
opening the duct on the wrong CRAC train had no affect on the operability of the
protected train. This deficiency was entered in the licensee's corrective action system as
CR M2-99-0986. The failure to follow the PM procedure is of minor safety significance
and is not subject to formal enforcement action.
Steam Generator Level and Automatic - Auxiliary Feedwater Initiation Loaic Functional
T_qs.t
The team observed the performance of surveillance procedure SP 2402M, " Functional
Test of Steam Generator Level and Auto - Auxiliary. Feedwater initiation Logic." The
instrument and controls (l&C) technicians performing this procedure stopped prior to
completion of the tests because certain relays could not be located. These relays had
been insta!!ed by a design change and were labeled differently in the field than the
nomenclature used in the procedure. While the technicians researched the location of
the relays, they left a jumper installed in the circuitry which provided an active auxiliary
p
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26
feedwater (AFW) pump initiation signal. This fact was unknown to the technicians, who
incorrectly communicated to control room operators that the AFW pump start signal was
,
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defeated by the jumper. There was no consequence as a result of this error since the
f
pump start was blocked by the pump handswitch being in the pull-to-lock position.
Engineering personnel determined that the relays had dual identification on the
drawings. The procedure used one form of identification, while the labeling in the field
used the other. The procedure revision, which was done to incorporate a design
'
change, was verified and validated by tabletop exercise instead of a field validation. The
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immediate corrective actions included a procedure revision to correct the relay
identification issue and describe the purpose of the installed jumper. The event was
discussed with the instrument and control (l&C) department technicians to sensitize them
to the importance of understanding the effect that procedure steps have on plant status.
Additionally, five other recently revised l&C procedures received field validation before
use. The condition was self-revealing during the surveillance performance, had no
i
safety impact, and corrective actions were appropriate. This inadequate procedure step
i
is a minor violation that is not subject to formal enforcement action.
125 Volt Direct Current (dcl Station Batterv and Turbine Batterv Surveillance
The team observed the weekly surveillance on the 125 volt de station and turbine
batteries. The technicians complied with the procedure, established appropriate safety
precautions, and correctly recorded the appropriate test data.
Chilled Water System Leak Surveillance
The team observed conduct of a leak test for one train of the chilled water system. The
periodic surveillance test was also being conducted as a post maintenance test for
valves replaced during the current outage. The personnel conducting the surveillance
were thorough in the examination of the system. They also identified material
deficiencies such as damaged insulation, a corroded support, and a leak in the bellows
of the air handling unit serviced by the chilled water system. The test personnel
appropriately failed the surveillance test when the acceptance criteria was not satisfied
due to leakage identified from a threaded connection.
Charaina Pumo Discharae Check Valve Test
The team observed a PEO manipulate the system to test the valves. The test procedure
referenced another procedure (the charging pump start-up procedure) in lieu of including
the required valve manipulation steps. The referenced procedure was not discussed
during the pre-job briefing, nor was the need to have the procedure available listed as a
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prerequisite in the test procedure. The lack of availability of the procedure locally did not
i
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adversely affect test performance since the equipment operator was able to contact the
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control room and have the required manipulation steps read to him. This procedure
problem was appropriately discussed during post-Job discussions.
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27
Maintenance Rework Rate
The team reviewed an analysis of rework conducted by the licensee's maintenance
~ engineering group which included a list of maintenance AWOs completed during the last
-
15 months that were considered to be rework items. The rework rate for that period was
about 1% of the total number of maintenance AWOs. The team also reviewed a list of
condition reports for rework items during the same period and selected several of these
for a detailed review. These items were well documented, with thorough analyses and
reasonable corrective actions.
c.
Conclusions
The quality of maintenance activities observed was generally good. Maintenance
technicians conducted good pre-job briefings in the maintenance shops and briefed
operators on job scope prior to beginning work,
i
Procedure adherence by the maintenance staff was generally good. The team observed
instances where work was stopped to clarify or revise maintenance procedures.
The maintenance workers were knowledgeable of assigned maintenance tasks and had
received appropriate training. The team concluded that the maintenance rework rate
'
was at an acceptable level, and that the licensee had adequately resolved maintenance
rework issues through the corrective action system. Appropriate maintenance
supervisory oversight of field activities was observed.
M2
Maintenance and Material Condition of Facilities and Equipment
a.
Insoection Scope
.
. The team assessed the adequacy of the material condition of the plant, including a
review of identified maintenance deficiencies, to verify that plant equipment condition is
acceptable to support a safe plant restart. The team reviewed deficiencies to ensure
i
they were prioritized and corrected commensurate with their safety significance. An
assessment of the Work-it-Now (WIN) and Backlog Reduction Teams was performed.
b.
Observations and Findinas
Plant Eauipment Condition
The team observed the condition of equipment located in the primary containment,
auxiliary, and turbine buildings. The appearance of plant equipment and facilities were
acceptable with no obvious indications of fluid leakage or other deficiencies not already
included in the licensee's corrective action program. Several significant plant equipment
improvements were installed during this outage (e.g., containment sump, replacement of
pressurizer spray piping, etc).
.
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28
'
Operator Burdens and Control Room Deficiencies
The team reviewed the licensee's operator burden and control room deficiency
programs. At the time of the inspection, the licensee had identified approximately 15
operator burdens. The team did not identify any additional operator burdens that were
not already included in the program. Where appropriate, the licensee proceduralized the
,
burdens in plant procedures. The team determined that the individual and cumulative
safety impact of the identified burdens was minimal.
The licensee had an adequate program to highlight important control room deficiencies.
j
The licensee had 29 deficiencies in the program at the time of this inspection. Fourteen
'
of these deficiencies had been corrected and were waiting for retests. The team did not
identify any additional control room deficiencies. The safety impact of the control room
deficiencies was minimal.
l
Maintenance Rule Systems
i
The team reviewed the maintenance rule action plans for six of thirteen (a)(1) systems.
The action plans were well documented and contained appropriate corrective actions.
They were prepared by the system engineer, and approved by the expert panel
l
chairperson and the unit 2 plant director. For (a)(1) systems, the system engineers were
required to write monthly status reports to the maintenance rule coordinator until the
systems achieved (a)(2) status. The team verified that corrective actions had been
completed or were documented in the corrective action system, and that monthly status
reports were being written.
The team noted that corrective actions identified in the latest (Revision 5) maintenance
'
rule action plan for the chilled water system were scheduled to be completed prior to
Mode 4 operation. In contrast, the " Plan of the Day Schedule" had these actions
identified as Mode 2 items. A CR (M2-99-0984) was written to resolve this discrepancy.
1
Maintenance Backloa
1
.The maintenance backlog impact on operations had been assessed by the licensee.
The team independently assessed the impact of the maintenance backlog and
determined that the backlog did not include any items that would adversely impact safe
plant operations. The backlog of work required to be completed prior to restart was
tracked by work control personnel with periodic status reports provided to plant
management. Daily meetings were conducted to assess the impact of emergent work on
plant operations.
The number of " Task Completions" required for restart had been reduced from 2825
tasks in April 1998 to 270 tasks in March 1999. The tasks included assignments
associated with NRC Open items, Significant item List issues, and CR corrective actions
as tracked in the licensee's Action item Tracking and Trending System (AITTS) but did
not include opened AWOs.
.
29.
. The AWO backlog was reported on a daily basis, with primary emphasis on the backlog
,
of items required for restart. The licensee trending reports showed a continual decline in
the number of AWOs working or in close-out/ retest status, with a slight increase in the
-number of AWOs deferred until after startup. On March 25,1999, at the end of the
inspection, the AWO breakdown included 370 items in the outage scope and 663 items
in the deferred work category. A review of the 370 outage scope items showed that the
majority of the AWOs involved minor issues, such as hot torque of bonnet fasteners,
!
' insulation replacement, and post heat-up inspections. A review of a sample of the
deferred items showed them to be issues that would not affect start-up, and can be done
on-line or during the next refueling outage.
The team also reviewed the licensee's listing of automated work orders (AWOs) required
- to be completed prior to restart. The review of open significant hardware AWOs showed
that the majority involved work steps which were to be completed as the plant startup
progressed. There appeared to be no significant hardware issues that would not be
corrected prior to operation of the plant.
.
Work-it Now OMN) and Backloa Reduction Teams
The WIN tearn consisted of a maintenance supervisor, two plant operators, two
maintenance technicians, and a planner / parts person. The WIN team worked primarily
on emergent maintenance issues. They used the same procedures and processes that
are in place for " normal" work. The WIN team was successful in the timely resolution of
emergent plant issues.
1
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The Backlog Reduction Team consisted of a Unit 3 supervisor; a mixed crew of Unit 3
mechanical, electrical and l&C mechanics and technicians; and a Unit 2 planner. The
i
Backlog Reduction Team spent two weeks resolving Unit 2 equipment deficiencies. For
example, the backlog team replaced teflon tape with approved joint sealants for
environmentally qualified electrical equipment. During the two-week assignment, the
,
backlog team reduced the Unit 2 AWO backlog by almost 100 items.
tig.usekeepina and Eauioment Storaae
The team observed that housekeeping was acceptable with most areas clean and well
maintained. A facilities betterment program was ongoing to improve the appearance of
various locations throughout the auxiliary building. The team noted a few unsecured
ladders, staging and scaffolding that, when brought to the licensee's attention, were
expeditiously restrained or removed.
.
30
c.
Conclusions
Necessary equipment repairs were either completed or scheduled for completion prior to
plant restart. Maintenance backlogs were being appropriately managed and routinely
assessed for impact on operations. The control of operator work-arounds and control
room deficiencies was also found to be adequate to support plant restart. The plant
material condition and housekeeping were acceptable. The Backlog Reduction and WIN
Teams had a positive impact on addressing emergent work and reducing the AWO
backlog.
These findings, along with the review of temporary modifications (bypass jumpers)
documented in Section E2.2 of this report, provide the team's basis for closure of NRC
Significant item List item 7, Bypass Jumpers, Operator Work-arounds & Control Board
Deficiencies and the associated NRC Restart Assessment Plan items.
M3
Maintenance Procedures and Documentation
M3.1 Maintenance Procedure Quality
a.
Insoection Scope
The team verified that the quality of maintenance and surveillance procedures were
adequate to safely perform the intended tasks.
b.
Findinas and Observations
The team reviewed selected maintenance procedures during work observations. The
team observ31 that generally the procedures were appropriate for the tasks being
performed es work packages and procedures were revised when appropriate.
The quality of the PM procedures reviewed were generally acceptable with one minor
exception. Preventive Maintenance Form 2701J-37 was not component or system
specific and could not be performed on the 'B' control room air conditioning system
evaporator fans during the semi-annual PM. The generic nature of the PM form required
the maintenance technicians to stop work and consult with supervision, resulting in being
in the control room air condition limiting condition for operation (LCO) for an additional
period of time (not exceeding the LCO). The licensee appropriately documented this
procedure deficiency in the corrective action program (CR M2-99-0988). The
inadequate procedure step is of minor safety significance and is not subject to formal
enforcement action.
The quality of surveillance test procedures reviewed were generally acceptable. One
exception was an l&C procedure where the " tabletop" validation and verification program
had not identified discrepancies between the procedure and control room labeling (See
section M1.1 for details). During this outage, the licensee verified that all required testing
had been included in the inservice testing (IST) procedures.
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c.
Conclusions
The team concluded that procedures reviewed were generally adequate for the intended
tasks.
M6
Maintenance Organization and Administration
M6.1 Maintenance Plannina and Schedulina
a.
Insoection Scope
The team assessed the maintenance work planning and scheduling processes to
assure adequate tracking, prioritizing and resolving of safety significant plant equipment
deficiencies. A sample of work packages was reviewed to evaluate their quality. The
. team also reviewed the licensee's process for evaluating risk when taking equipmr.it
out-of-service for maintenance. The team also verified that surveillance tests P.;id
preventive maintenance scheduling were appropriately cuntrolled.
b.
Observations and Findinas
Work Plannina
The team reviewed approximately 30 work packages. The work packages were found to
-be satisfactory and the work instructions were sufficient for the scope of work. Changes
to work packages and procedural steps had been performed in accordance with the
appropriate administrative controls.
The team noted that the planning department had a large backlog of completed AWOs
for final closure. This backlog had no noticeable effect on the completion of work in the
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field.'
Schedule Adherence
The adherence to plant schedules had been poor. On average, only 46% of work orders
on the 3-day look ahead schedule were started and 42% were completed on schedule.
The difficulty in meeting schedules was attributed to several factors including emerging
issues, focus on outage critical path items and supporting mode changes. During the
inspection, the team noted several instances where maintenance tasks were delayed in
.
starting, or interrupted in progress, due to unforseen difficulties or changes in priorities.
Maintenance manager.was observed to emphasize doing the job right, rather than being
'
overly concemed with schedule adherence.
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Risk Assessments
1
The team reviewed licensee activities relative to the assessment of safety during
' maintenance activities.-The team noted that the risk sensitivity of planned activities was
communicated to alllevels of the maintenance organization. Plan-of-the-day meetings
' discussed the risk status of the plant, including which facility was protected, as a
standard topic of discussion.
The team noted good communication of plant risk and safety status within the
maintenance department. The risk status of the plant and the potential effect of planne.1
maintenance activities were discussed during daily supervisors meetings and daily crew
meetings. Biweekly department meetings held by the maintenance manager were also
prefaced by a discussion of the safety status of the plant and the risk significance of
ongoing activities.
At the time of this inspection, the licensee was in the final stages of initiating a 12-week
i
rolling schedule for Unit 2 on-line maintenance and surveillance activities. The process
was scheduled for implementation on April 4,1999, using new station procedures
applicable to both Units 2 and 3. As a part of the " lessons-leamed" from Unit 3, phased .
implementation was planned for Unit 2. The first phase included integration of
surveillance and preventive maintenance activities (scheduled using the 12-week
scheduling process) with corrective and emerging maintenance activities (scheduled
using the outage scheduling process). The first phase of the 12-week scheduling
process was performed by a Unit 3 scheduler to mentor the Unit 2 schedulers and to
incorporate lessons leamed from Unit 3.
PM Proaram Schedulina
The PM program included a set of regenerating work orders that were entered into the
production maintenance management system (PMMS). The team noted that the system
may be prone to human errors because it required the planner to manually regenerate a
PM during AWO closure or the PM would not be rescheduled. In addition, a missed or -
deferred PM would not adjust the next quarterly PM, but the corresponding next year's
PM would be adjusted. The licensee's staff were aware of these scheduling limitations.
The team did not identify any cases where the potential process weakness resulted into
inadequate scheduling of PMs.
The team noted that the Condition-Based Maintenance (CBM) Department has
developed, but not implemented, a monitoring, testing and maintenance program to
improve component reliability. The CBM Department had recently issued a procedure to
improve the PM program through periodic review of corrective maintenance activities.
Prior to the issue of this procedure, trending of trouble reports and corrective
maintenance on individual components had been an informal pre-outage function of the
maintenance planners.
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The team found that the PM deferrals were adequately documented and readily
recoverable. - During the outage, the licensee had reduced the number of overdue PMs
' from approximately 200 to 7. The team noted that the deferral documentation was not
always timely. Five of the seven overdue PMs had deferral requests still pending.
Surveillance Testina Procram Schedulina
The team reviewed the licensee's restart surveillance scheduling program. The licensee
demonstrated that the planned and/or completed surveillance testing would adequately
support the restart of the unit. As a part of the surveillance schedu'ing, refueling cycle
surveillance tests had been put on an 18-month schedule during the maintenance
outage, with the start of the current 18-month cycle being November 1998.
c.
Conclusions
Performance in the area of planning and scheduling was mixed. Planning was thorough,
with detailed work packages prepared to support most AWO activities. Schedule
adherence did not meet licensee's goals primarily due to emergent issues. The team did
,
not observe any instances where schedule pressures or changes adversely affected
plant safety.-
The licensee's performance in assessing the safety / risk of planned maintenance was
,
acceptable. Safety assessments for maintenance activities were addressed by
appropriate procedures and the risk significance of planned activities was discussed at
planning meetings.
The licensee had identified and/or completed surveillance tests required for plant restart.
The team's findings provide the basis for the closure of SIL item No. 6, Work Planning
and Control, and the associated NRC Restart Assessment Plan items.
IV. Enaineerina
E1
Conduct of Engineering
a.
Insoection Scope
The team evaluated the effectiveness of the technical staff, including design and
technical support (system) engineers, in supporting the safe operation of the plant. The
team also assessed system and design engineering response to emergent (day-to-day)
plant technical problems including an assessment of communications and interfaces,
timeliness, and technical adequacy of the support. The team also verified that issues
were being properly prioritized and effectively resolved in a timely manner.
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34
b.
Observations and Findinos
The engineering departments provided good support for day-to-day activities and were
properly represented at various meetings observed by the team. A key member in this
respect was the engineering duty manager who served as the primary point of contact
for engineering in their interface with other plant departments. The engineering staff
members were knowledgeable of issues and provided good support to other
departments.
The daily engineering moming meeting provided good discussion of emergent issues,
new CRs and the status of ongoing activities. The responsibility for issues was clear and
individual accountability for completing tasks was evident.
The team screened the list of open CRs that required engineering actions to close. From
this list the team selected several for additional review, including CRs generated during
the two-week inspection period. The team found that the licensee properly evaluated
and prioritized the issues for resolution.
The team also reviewed the corrective action plans and implementation of corrective
actions for a number of CRs listed at the end of this inspection report. The team found
the corrective actions were generally appropriate and effectively implamented. However,
in one case, when a problem was identified with the bend radius of a cable within a
conduit fitting, the initial investigation did not fully investigate the potential scope of the
problem. Subsequent actions were taken to inspect aoditional cables in similar conduit
-
-
"
fittings and the overall issue was evaluated and documented by the licensee in M2-EV-
99-0015, " Technical Evaluation for Cable Bend Radius in Conduit Fittings - Millstone Unit
2." The inspectors reviewed the document and determined that the additional actions
and technical evaluations appropriately addressed this issue.
System Readiness Reviews
The system readiness reviews required the System Engineers (SEs) to conduct a broad
i
review of several aspects that contribute to system readiness. The team reviewed -
I
approximately ten system readiness review reports and found them to be
comprehensive. The system deficiency backlogs had been appropriately reviewed and
dispositioned._The team determined that the SEs were knowledgeable of the system
readiness reviews and were cognizant of plans to address those issues needing
q
- corrective action prior to plant startup.
Syjtem Walkdowns
The team walked down a number of safety systems and interviewed the responsible
'
system engineers regarding system status. The SEs were knowledgeable of the open
' issues and appropriately involved in resolving issues related to their systems.
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The engineering departments were fully staffed and were functioning effectively.
Engineering personnel, including supervisors and managers, provided around-the-clock,
on-site support of activities including items such as post-modification testing,
c.
Conclusions
The engineering department managed the planned and emergent activities well. Daily
planning of issues at the moming meeting set the priorities of both the system and
design engineering departments. Communication with and support to other departments
'
was good. The identification, documentation and control of issues within the CR system
was good. Corrective actions associated with CRs and other open items were properly
tracked within the action item tracking and trending system (AITTS). The team did not
, identify any CR issues that had not been properly screened and dispositioned for
deferral until after the restart. These findings provide the team's basis for the closure of
NRC SIL 7, items C.3.2.e, Effectiveness of corporate engineering support, and item
C.4.f., Significant hardware issues resolved.
E2
Engineering Support of Facilities and Equipment
E2.1
Permanent Plant Modifications
a.
Insoection Scope
.The team reviewed several modifications that were installed during the current outage to
verify that the modifications were installed in accordance with program requirements and
that the modifications did not reduce plant safety margins. The team also verified that
the engineering resolutions of the issues being addressed by the modifications were
technically sound and that the safety evaluations provided an adequate basis for
determining if the changes involved an unreviewed safety question. The team also
riviewed the modification closeouts to ensure that drawings were revised, post-
niodification testing was performed, and that plant procedures and vendor manuals were
i.pdated.
b.
Observations and Findinas
The team reviewed several plant modifications and minor modifications (MMODs) that
were completed during the outage. The engineering of the design changes was
technically sound and thoroughly documented in accordance with the Design Change
Manual (DCM) requirements. The team found that the safety evaluations included good
bases to support the conclusions relative to determining if the change constituted an
unreviewed safety question. The modification closeouts were complete, drawings and
procedures were properly revised, appropriate post-modification testing was performed,
and vendor information was updated.
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36
'
.The team also reviewed several maintenance support engineering evaluations (MSEEs).
MSEEs were used to provide engineering support to maintenance or operations to
implement enhancements that did not constitute design changes. The use of an MSEE
must be approved by the design engineering manager, must be documented on a design
change notice (DCN) and evaluated in accordance with 10CFR50.59 to ensure it does
not constitute an unreviewed safety question. The team found that the MSEEs were
implemented in accordance with the DCM and were of a good technical quality.
Drawings and other documents affected by the MSEE were appropriately updated.
The team reviewed the function and results of the engineering Quality Review Board
(QRB). The purpose of this board is to review all primary engineering documents
(DCRs, MMODs, MSEEs, TMs) for technical and administrative quality before they are
sent to the PORC committee for approval. The team attended a QRB meeting held to
review a MSEE and found the review by the board to be very thorough.
The engineering design manager has tracked the engineering rework rate since the
inception of the QRB and the statistics indicated a marked improvement in the products
'
being presented. The increase in quality was also reflected in a reduced rejection rate
(to near zero) of engineering documents by the PORC committee.
c.
Conclusions
The team found the design control process was being properly implemented. The
technical quality of changes was good and modification package content, including the
10CFR50.59 screening and safety reviews, are comprehensive. Post-modification
testing accomplished the verification ofimportant design change attributes. The use of a
Quality Review Board has contributed to improvements in the quality of the engineering
products.
E2.2 Temoorary Modifications
a.
Insoection Scope
The team reviewed the existing temporary modifications (TMs) to verify that they were
installed in accordance with the procedural requirements and to assess the operational
impact of the TMs intended to be installed at the time of plant restart. During plant
walkdowns, the team examined systems to identify if any potential modifications existed
to station equipment that were not being properly controlled by the TM process. The
existing TMs were discussed with the responsible system engineers (SEs) and design
engineers to assess their knowledge of the TM process, the effect on system operation
and the proposed resolution that will allow removal of the TMs.
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37
b.
Observations and Findinas
'
There were a limited number of TMs in place at the time of the inspection and they were
-
- - installed and controlled in accordance with the administrative proceduresc The TMs
were properly documented and the documentation included appropriate safety analyses
and technical evaluations. Affected procedures were properly revised where necessary.
The SEs, design engineers and engineering supervisors were knowledgeable of the
installed TMs and with the planned actions to resolve the condition requiring the TMs.
Of the eight temporary modifications installed at the time of the inspection only two had
the potential to directly affect safety related systems. Temporary modification 2-96-083
documented a problem with the emergency diesel generator (EDG) room drain header
check valve. The valve had been temporarily repaired and local backwater flapper
valves were installed in each of the individual drains. The flapper valves were leak
tested prior to installation to ensure there would be minimal inleakage in the event of an
external flood. A calculation was also performed to ensure that any minor back leakage
would be detected by the operators before any safety-related equipment could be
impacted.
Temporary modification 2-99-06 was installed during the inspection to jumper the low air
flow alarm contact for vitalinverter 4. The air flow instruments were designed to detect a
reduction in cooling air flow through the inverter. Due to an apparent malfunction of a
circuit card, the instruments were causing spurious alarms in the control room. The low
flow alarm contact was jumpered to prevent the nuisance alarms until the cause could be
identified and corrected. The temporary modification contained a thorough technical and
safety evaluation. Additional alarms remained active following the installation of the
jumper and included a high temperature alarm.
During plant walkdowns, the team questioned if temporary cameras installed in various
areas of the containment were controlled by a temporary modification. This question had
also been raised by a member of the oversight department. The cameras had previously
been controlled by a procedure but the licensee now concluded that it would be more
appropriate to control them with a temporary modification. The licensee was preparing a
temporary modification that was to be implemented prior to plant restart.
b.
Conclusion
Engineering has been effective in resolving issues. As a result, the use of temporary
modifications was minimal. The number of installed TMs was low and below the plant
goal. The team concluded that the evaluation and control of temporary modifications
was good and that the installed TMs had no adverse impact on safe plant operation.
,
1
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E2.3 Deferred lasues Reyigg
a.
Insoection Scooe
The team reviewed the deferred engineering work request (EWR) backlog and selected
several issues for detailed review to assess plant impact of not completing these items -
~ before restart. Additional inspection of items to be completed after restart was also
performed as documented in section S2.2 of this report.
b.
Observations and Findinas
The team selected a sample of the deferred EWRs for review based on their potential -
safety significance in review of these EWRs, the team did not identify any restart issues
and the EWRs reviewed had adequate bases for deferral.
c.
Conclusions
The licensee had adequate controls in place to ensure deferred work was properly
evaluated. No deferred modifications were identified that would affect safe plant
operation.
E2.4 Enaineerina Support to Plant Operations
- a.
Inspection Scope -
The team compared the surveillance procedures for the control room heating and
ventilation (HVAC) system, to the design criteria and testing requirements contained in
the Final Safety Analysis Report (FSAR) and plant Technical Specifications (TS). The
team also examined the HVAC system readiness review document, and conducted a
walkdown of the system with the cognizant system engineer.
- The team examined HVAC surveillance procedures to determine if surveillance testing
was conducted in accordance with the testing requirements outlined in the plant TS, and
1
to verify the design assumptions used in the surveillance procedures accurately reflected
i
.
system performance criteria contained in the FSAR. A system walkdown was performed
to examine the physical condition of the system, and verify the system engineer was
familiar with the operations of his system.
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39
b.
Observations and Findinos
During the current outage, the licensee conducted an extensive review of the HVAC
j
system design analysis, surveillance and operating procedures and maintenance
practices. The review was thorough and numerous deficiencies were detected. The
issues included the discovery of single failure vulnerabilities, inadequate surveillance
procedures, and inconsistencies between the system design analysis specified in the
FSAR, and TS. To resolve these issues, the control room HVAC system was modified,
surveillance and operating procedures were rewritten and the system design analysis
was revised.
Modifications to the control room system included locking certain backdraft dampers in
place to eliminate single failure vulnerabilities and sealing holes in the ventilation system
ductwork to reduce control room air in leakage. The licensee also established additional
administrative controls to minimize system unavailability by ensuring work that could
disturb the control room boundary was completed in a timely manner.
The control room surveillance testing program was robust. Not only #d the testing verify
the system would meet the performance criteria established in the FSAR and plant TS,
but certain aspects of the testing utilized state-of- the-art performance monitoring
equipment not generally used by the industry. Specifically to measure control room air in
leakage, the licensee used a tracer gas. Industry testing has revealed that a tracer gas
is more likely to find degradation in the control room pressure boundary than other less
sensitive, but acceptable, methods such as air pressure drop testing.
l
Recent revisions to the sections of the plant TS and FSAR, which discussed the control
room HVAC system, removed inconsistencies that existed between the two documents.
For example, prior to one change, the dose assessment for the control room operators
described in chapter 14 of the FSAR, assumed the minimum air flow through the control
room charcoal filters was 2500 cubic feet per minute (cfm). This assumption was not
conservative, since the minimum filter air flow allowed by the plant TS was 2250 cim.
The revised chapter 14 duse assessment for control room operators, properly assumed
a charcoal flow rate of 2250 cfm.
The readiness review conducted on the system was thorough and appeared to capture,
i
assess, and resolve remaining design, maintenance and procedure deficiencies.
l
The system engineer demonstrated familiarity with the operation of the control room
HVAC system, its maintenance history, and recent modifications it had received.
c.
Conclusions
The licensee had substantially improved the design and licensing basis of the control
room HVAC system. Inconsistencies between the system design criteria contained in
the FSAR, TS and the operating and surveillance procedures were eliminated. Single
failure design errors were corrected. The system readiness review was thorough. The
i
control room HVAC surveillance testing program was a strength.
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. . .
E'3
Engineering Procedures and Documentation
j
E3.1 ' Ooerability Determinations
a.
Insoection Scope
The team reviewed the open operability determinations (ODs) at the time of this
j
- inspection to assess the technical adequacy of the evaluations and the potential impact
'
on safe operation.
b.
Observations and Findinas
~ The OD process was consistent with the guidance provided in NRC Generic Letter 91-
18, Revision 1, "Information to Licensees Regarding NRC Inspection Manual Section on
Resolution of Degraded and Nonconforming Conditions."'
There were approximately 26 open operability determinations at the time of the
inspection. The ODs were readily accessible via computer and a hard copy was
maintained in the shift manager's office in the control room. The ODs were thorough
and provided sufficient detail to establish operability. The team reviewed all the open
ODs and determined that they were acceptable to support plant restart or that the
licensee had assigned an appropriate mode restraint for the resolution of the issue which
required the evaluation. The team discussed many of the ODs with engineering
department managers, supervisors and engineers. The engineering personnel at all
levels had a good understanding of the issues, and for each of the conditions described
in the ODs, there was an appropriate plan for resolving the degraded or non-conforming
condition.
c.
Conclusions
The OD process was comprehensive. Operability determinations were technically sound
and documented an adequate basis for establishing operability of the degraded
'
component or system.
!
E3.2 Vendor Manual Control
a.
Insoection Scooe -
The team reviewed the engineering products to ensure that control of vendor equipment
technical manual information was included in engineering documents. The licensee
program for control of vendor information was previously reviewed by the NRC in SIL
ltem 50,
b.
Observations and Findinas
The team found that engineering documents, such as design changes and maintenance
support engineering evaluations, included updates to vendor manuals.
m
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41
i
t
c.
Conclyginns
i
.The licensee program to maintain the accuracy of vendor manual information was being
properly implemented.
E3.3 . Setooint Controls
a.
Inspection Scope
The team assessed the setpoint control process for safety-related plant equipment. The
team reviewed selected setpoints for safety-related functions and emergency operating
procedure (EOP) operator actions to assess their adequacy and safety basis.
b.
Observations and Findinas
The team reviewed Specification SP-ST-EE-329, " Standard Specification for Use and
Control of Master Setpoint index," Rev. 2, and Specification SP-M2-lC-019, " Millstone
Unit 2 l&C Setpoints," Rev.1. These specifications clearly delineated the bases for
incorporating instrument uncertainty into safety related setpoints. Additionally, the
current bounding values of the reactor protection system (RPS) and engineered safety
1
features actuation system (ESFAS) setpoints along with emergency operating procedure
action points were incorporated into SP-M2-IC-019. The team found that an adequate
process was in place to control setpoints.
Revision 4 to CEN-152, " Combustion Engineering Emergency Procedure Guidelines",
. was issued, in part, to incorporate information gained through the Combustion
Engineering Owners Group (CEOG) instrument uncertainties study. Specific CEOG
guidance on instrument uncertainties was provided in study CE-NPSD-1009 Rev. O, "l&C
Engineering Limits and Bases EOPs." In a letter dated May 7,1997, the licensee stated
that any safety significant items identified as part of the Millstone Unit 2 instrument
uncertainties study would be incorporated into the EOPs prior to restart from the current
outage. The team sampled several parameters, which had been identified as having a
1
high degree of safety significance, in the CEOG guidance.
Calculation, S-01228-S2, Rev. 2, " Millstone 2 Emergency Operating Procedure Setpoint
Documentation", provided the bases for setpoints used in the EOP's. Fifteen setpoint
bases were reviewed along with appropriate supporting documentation. The team found
the decision to include or not to include instrument inaccuracies to be sound for the given
parameters. Significant EOP changes had been made which incorporated potential
instrument errors for harsh environments. For example, revised pressurizer pressure
instrument inaccuracies were incorporated into new pressure-temperature curves and
shutdown cooling temperature and pressure entrance criteria in the EOPs.
The team found the bases for the setpoints reviewed to be adequately justified. With one
exception, the team found that supporting setpoint calculations were generally
comprehensive and utilized appropriate design inputs and assumptions. The exception
involved the refueling water storage tank (RWST) level setpoint.
..
.
42
During a review of calculations 92-030-1259E2, Rev. 2, "RWST Level Setpoint Analysis,"
and 98-ENG-02558M2 Revision 0, " Determination of Minimum Submergence Criteria for
RWST Suction Piping," the team noted that the minimum submergence value for the
. suction pipe had been calculated assuming a post-sump recirculation actuation signal
(SRAS) operating condition. At that point the low pressure safety injection pumps (LPSI)
are automatically secured, resulting in a reduced fluid velocity. The team determined
that using the lower fluid velocity in the calculation could result in a calculated
submergence value which would be non-conservative for the tank level that would exist
just prior to the SRAS signal inadequate suction pipe submergence could result in flow
vortexing and subsequent air entrainment in the flow path to the safety related pumps.
The licensee initiated condition report M2-99-1107 to evaluate this condition.
On March 25,1999, a calculation change notice was approved which concluded that the
present setpoint was acceptable. The new calculation now credited anti-swirl vanes on
the intake pipe and determined that the minimum submergence level to avoid air
ingestion was 25 inches above the bottom of the tank in the pre-SRAS condition. This
value was bounded by the existing minimum analytical setpoint of 26 inches above the
bottom of the tank in the post-SRAS condition. The team determined that this new
calculation supported the basis for the reasonable expectation of continued operability
documented in the condition report.
During a review of the bases for the EOP action setpoints associated with HPSI pump
discharge pressure transmitters, the team questioned the use of these instruments
during the recirculation phase following a loss of coolant accident (LOCA). Specifically,
during the recirculation phase following a LOCA, the transmitters would be subjected to a
potentially harsh radiation field. However, they were not environmentally qualified.
The pressure transmitters were used in EOP 2532, " Loss Of Primary Coolant", to verify
that HPSI pump run-out conditions did not exist following post SRAS alignment to the
containment sump. Following SRAS, it could be postulated that the operator may throttle
HPSI injection flow when not warranted based on erroneous readings on the unqualified
,
pump discharge pressure instrument. Additionally, FSAR Table 7.5-3, " Regulatory
i
Guide 1.97 - Accident Monitoring Instrumentation," did not reference the pressure
transmitters or credit their use in post accident conditions.
The team noted that calculation 97-122 Rev. 2, " Millstone Unit 2 ECCS System
Analysis," had concluded that based on the HPSI throttle valve position settings, runout
would not be a concern. The team also noted that in the event the operators had
inadvertently throttled HPSI flow, there was additional instrumentation, such as core exit
thermocouples and reactor vessel water level, which would have provided for
determining the adequacy of core cooling. The licensee initiated condition report
. M2-99-1122 and stated that the use of the pressure transmitter would be removed from
,
the emergency operating procedure during the next revision which was scheduled to be
performed prior to plant restart. The failure to adequately translate the design basis into
procedures constituted a violation of minor significance and is not subject to formal
enforcement action.
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43
c.
Conclusion
The licensee implemented an adequate setpoint process and the Millstone Unit 2
"
- Instrumentation and Control (l&C) setpoint specification provided a clear definition of the
program for the generation and documentation of safety-related, instrument and control
setpoints. In general, the setpoints selected for review by the team were properly
documented, reviewed, and supported by appropriate calculations.
E3.4 Eauipment Qualification
a.
Insoection Scope
The team reviewed a sample of item equivalency evaluations (IEEs) and commercial
grade deoications to ensure equipment was appropriate for use in safety systems. The
team reviewed the packages for several commercial grade items which included
individual parts as well as dedication of components such as air conditioning units,
transfer switches and transmitters.
b.
Observations and Findinas
The. team found that the procedures and processes for the equipment reviews were
technically sound and provided adequate controls. This procedure provided reasonable
assurance that a commercial grade item selected for use would perform its safety-related
function.
The evaluations reviewed were thorough and applicable data bases and documents
were properly updated. The program effectively involved the appropriate departments,
such as design engineering, in the evaluation review process and in the implementation
of evaluation results such as updating of procedures or specifications.
c.
Conclusion
The licensee implemented effective commercial grade dedication and item equivalency
evaluation programs and performed appropriate evaluations to support plant restart.
E3.5 Ooeratina Experience Proaram
a.
insoection Scope
The team reviewed the licensee operating experience procedures to assess the
adequacy of the program. The team reviewed a sample of completed operating
experience evaluations which had been designated as operational mode holds to assess
the adequacy of issue resolution. The team also reviewed a sample of open operating
experience (OE) items to assess whether appropriate priorities had been assigned for
issue resolution.
L__.
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b.
Observations and Findinas
The team found that the Nuclear Safety Engineering (NSE) Group had been
administering the operating experience assessment program in accordance with NSE 1,
Rev,0, " Implementation of Operating Experience." The reports were thorough and
provided, when required, appropriate recommendations to address the related issues.
Recommendations made were tracked through resolution by the NSE group.
1
The team reviewed five OE issues which had previously been designated as start up
restraints. The team found that proposed and completed corrective actions justified
removing them from operational mode holds. OE documents currently under evaluation
were reviewed and found to be properly prioritized.
c.
Conclusions
The team concluded that the operating experience program was functioning adequately
to support restart. The backlog of reviews had been evaluated by the licensee to identify
those issues requiring review before restart and appropriate priorities had been assigned
to these issues.
E3.6 Drawina Control
a.
Inspection Scope
The team reviewed the adequacy.of drawing controls and the status of operations critical
drawings to ensure they were acceptable to support plant restart.
. b.
Observations and Findinas
Over the last 12 months there were 225 condition reports that docuniented
drawing / configuration deficiencies. Of the 225, only five issues necessitated preparation
of operability determinations, of which none of the issues resulted in operability issues.
The five items of concern documented the discovery of longstanding
design / configuration issues that did not appear to be indicative of current plant
performance. The team found that recently completed plant modifications had been
accurately reflected in control room operational critical drawings within the time
requirement specified in the DCM.
c.
Conclusions
The majority of the drawing issues that have been identified over the past 12 months
have had minor safety significance. Current procedures and processes for updating
operational critical drawings in the control room had been followed.
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45
E8'
Miscellaneous Engineering issues
E8.1
Emeroency Core Coolina Systems Sinale Failure Vulnerability
a.
Insoection Scooe
The team reviewed the corrective actions taken by the licensee to address the single
failure vulnerabilities for post loss of coolant accident boron precipitation strategy and the
isolation of the safety injection tanks. The team reviewed selected design change
documentation, inspected the installation of the design changes, and reviewed the
operating procedure changes. The team verified that key aspects of installation were
!
consistent with the design change documentation.
b.
Findinas and Observation.s
On January 9,1998, the licensee identified single failure vulnerabilities in the strategies
used for controlling boron precipitation in the reactor vessel and isolation of the safety
injection tanks (SITS) following a loss of coolant accident (LER 98-002). Both system
alignments used to mitigate the affects of boron precipitation in the reactor vessel would
be compromised if a failure of either an altemating current (ac) or direct current (de)
electrical facility were to occur. The licensee addressed this concern by installing a
design change that allows either electrical facility to power key valves in the boron
precipitation flow path. The licensee also identified that the failure of either train of
electrical power could also prevent the isolation or venting of nitrogen gas from the
safety injection tanks. . Introduction of nitrogen from the SITS into the reactor coolant
. system following an accident could have an adverse affect on core cooling. A design
change was installed that allowed either SIT isolation or venting of the SIT nitrogen cover
gas concurrent with a single failure of either electrical facility. The design change
electrically powered the SIT vent valves and isolation valves from opposite electrical
facility.
The team noted that the emergency operating procedure changes made to implement
i
the boron precipitation design change were incorrect. The licensee stated that these
procedures had only been conditionally approved by the PORC and further validation,
verification and procedure revisions were known to be required. The licensee
demonstrated that the procedure deficiencies noted by the team had ueu oreviously
identified by the design engineering organization. - A condition report (CR) was icsued to
review the circumstances surrounding the conditional PORC approval of the emergency
operating procedures (EOPs) and the conditional PORC approval for the EOPs was
temporarily withdrawn.
_.
4
1
46
c.
Conclusions
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l
' The team concluded that the design changes resolved the ECCS single failure
vulnerabilities. Additionally, the aspects of the design changes reviewed, with the
{
exception of the EOP changes, had been properly implemented. The licensee
j
demonstrated that appropriate administrative controls were in place to ensure that the
j
EOPs would be corrected prior to becoming effective. These findings provided the basis
necessary for the closure of SIL 53.1.
E8.2 - (Closed) LER 97-034-00: Containment Sumo isolation Valves are Susceptible to
Pressure Lockina
t
a.
Insoection Scope
t
Licensee Event Report (LER) 97-034-00 was submitted to document the discovery that
valves 2-CS-16.1 A&B could be susceptible to pressure locking due to variations in
containment pressure. The team reviewed the licensee's actions to resolve the
l
documented discrepancy.
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i
b.
Observations and Findinas
l
i
The licensee identified the apparent design weakness while performing a review of a
j
previous modification to these valves that had been made to prevent the possibility of
j
thermally induced pressure locking. The review found that the valves could be
l
I
pressurized to 54 pounds per square inch gage (psig) during an accident where previous
analysis had only postulated an initial bonnet pressure of 37 psig. Because preliminary
calculations indicated the motor operators may not be adequately sized to open if the
bonnet was pressurized to 54 psig during an accident the valves were declared
l
inoperable. Subsequent testing in April 1998 indicated that the valves would have
j
functioned properly and were operable. Nonetheless, the licensee chose to modify these
valves to prevent bonnet pressurization.
1
To resolve this concern, the licensee installed a pressure relief system on the valves that
would prevent bonnet pressure from reaching a point at which the potential for pressure
locking could be a concern. At the time of the inspection, the modification had just been
declared operable. The team reviewed the control room design drawings and valve
lineup sheets and verified they had been updated to reflect the addition of the
modification.
!
l
Additional corrective actions included examining all remaining safety-related valves to
4
determine if they were susceptible to pressure locking or thermal binding (PLTB). No
new issues were identified. To ensure the full range of accident conditions are
j
considered during future pressure locking / thermal binding reviews, the "MOV System
!
and Design Basis Review instruction" was changed to require Nuclear Engineering (NE)
to perform the MOV analysis. The licensee believes that the NE department, which
develops the plant safety analysis, will be better suited to identify similar analysis errors.
The team verified that the instruction was revised.
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47
PLTB of gate valves was the subject of Generic Letter 95-07, " Pressure Locking and
Thermal Binding of Safety-Related Power Operated Valves." This letter required,
licensees in part, to examine all safety related valves for susceptibility to PLTB, modify
them as appropriate, and inform the NRC of the results. The team noted subsequent to
the identification of this issue, the office of Nuclear Reactor Regulation had reviewed
NNECo's revised PLTB program and determined it was adequate. This conclusion was
i
outlined in a November 24,1998 safety evaluation report.
c.
' Conclusions
The licensee's corrective actions were considered appropriate to correct the issue
'
identified in LER 97-34. The licensee's April 1998 pressure locking tests indicated the
valves would have remained operable and therefore the error was of minor significance.
However, the failure to use appropriate assumptions when initially analyzing the
containment sump valves for susceptibility to PLTB was a weakness in design control.
These findings provided the basis necessary for the closure of SIL ltem 20.7A and LER
50-336/97-034.
V. Manaaement Meetinas
X1
Exit Meeting
The team held an exit meeting that was open for public observation, on April 7,1999.
The slides used by the NRC to conduct presentations during the exit meeting are
provided as Attachment 1 to this inspection report. The licensee acknowledged the
findings presented. The data base used to track inspector's requests / questions and
licensee responses will be placed in the Public Document Room.
INSPECTION PROCEDURES USED
IP 93802: Operational Safety Team inspection (OSTI)
>
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
NCV 99-04 Missed Technical Specification Survaillance to monitor steam generator temperature
g
1.
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Closed
LER 97-034
SIGNIFICANT ITEMS LIST
Closed
. Management Oversight and Effectiveness; Licensee Staff Safety Culture
,
Sll 6
Work Planning and Control
'
. SIL 7
Bypass Jumpers, Operator Work-Arounds and Control Room Deficiencies
Licensee Restart Punch List - Review Items Deferred Until After Restart
Operation Performance
LSIL 20.7 Pressure Locking of Valves
3
SIL 53.1, Single Failure of ECCS
LIST OF ACRONYMS USED
AITTS
action item trending and tracking system
Assistant Operations Manager
AWO-
automated work order
AOP_
abnormal operating procedures
l
.CBM
condition based maintenance
CFR
code of federal regulations
CFM-
cubic feet per minute
corrective maintenance
'
,
' CO
control operator
COEG
Combustion Engineering Owners Group
,
CR
condition report
CRAC
control room air conditioning
condensate' storage tank
direct current
design change manual
.DCR
- design change request
DR -
discrepancy reports
EDG.
emergency operating procedure
. engineered safeguard actuation system
engineered safety feature actuation system
engineering work request
final safety analysis report .
t
I
. HPSI.
high pressure safety injection
heating ventilation and air conditioning
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lCAVP.
independent corrective action verification program
i
institute of nuclear power operations
j
l&C
instrumentation and control
]
lEEs
item equivalency evaluations
IR
NRC inspection report
1
IST.
Inservice test
JUMA
joint utilities management assessment
j
KPI
key performance indicator
'
LCO-
' limiting condition for operation
LER
licensee event report
localleak rate testing
loss of coolant accident
low pressure safety injection
MMOD
minor modification
motor-operated valve
MSEE
maintenance support engineering evaluations
NE
nuclear engineering
NGP
nuclear group procedures
northeast nuclear energy company
NSE
nuclear safety engineering
NORP
nuclear oversight verification plan
NRC-
nuclear regulatory commission
NSAB
nuclear safety assessment board
NU
northeast utilities
operating experience
,
OP
operating procedure
'
operations
ORP
operational readiness plan NU
OSTI
operational safety team inspection
post accident sampling system
plant equipment operator
i
public document room
P&lD _
piping and instrument drawing
PLTB
pressure locking and thermal binding
PRA~
plant operations review committee
FM
preventive maintenance
PMMS
production maintenance management system
PSIA
pounds per s'uare inch absolute
' PSIG
pounds per square inch gage
-
PUP.
procedures upgrade program
quality control
QRB
_ quality review board
NRC Restart Asaussment Penel
reactor building closed cooling water
.RCS_
--
.
b
50'
RWST -
refueling water' storage tank
system engineers
Sll
significant issues list
safety. injection tank
SM:
shift manager
'SORC
site operations review committee
i
surveillance procedure
SPROC.
special procedure
turbine driven auxiliary feedwater
TM
- TS
technical specification
UlR
' unresolved item report '
-. US
unit supervisor-
)
. ultrasonic test
-VCT
volume control tank -
.V&V
validation and verification
- WIN
work-it-now
.Y2K-
year 2000
.
- PARTIAL LIST OF DOCUMENTS REVIEWED
MANAGEMENT PROGRAMS AND OVERSIGHT:
Progress Toward Readiness Restart at Millstone 2, January 8,1999
I
Unit 2 Restart Following 10CFR50.54(f) Outage, SPROC OP 98-2-08
Post-Maintenance Testing, CWPC 3, Revision 2
' Millstone Self-Assessment of the Retest (for AWOs)
>
. CRs related to Retests'
4
R. P. Necci to U. S. Nuclear Regulatory Commission, " Millstone Nuclear Power Station, Unit 2,
i
Response to April 16,199710 CFR 50.54(f) Information Request," February 5,1999
R. P. Necci to U. S. Nuclear Regulatory Commission, " Millstone Nuclear Power Station, Unit 2,
Response to April 16,199710 CFR 50.54(f) Information Request," March 5,1999
R. P. Necci to U. S. Nuclear Regulatory Commission, " Millstone Nuclear Power Station, Unit 2,
. Independent Corrective Action Verification Program, Final Report - Volumes 1 and 2
Additional Comments," March 5,1999
NOQP 1.08, Nuclear Oversight Verification Plan (NOVP)
,
NOQP 2.01, Nuclear Oversight Audits
NOQP 2.04, Nuclear Oversight Assessments
NOQP 3.04, Nuclear Safety Engineering Functions & Responsibilities - ISEG and Operating
- Experience Assessment -
Oversight evaluation by Key issue Leads / Nuclear Oversight Leads
Northeast Utilities Nuclear Group, Nuclear Oversight Assessment, independent Assessment
Team, July 1997 -
e
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51
,
1998 Joint Utility Management Assessment (JUMA) Report for the Millstone Station
Necci to Kenyon, RPN 99-015, Nuclear Oversight Monthly Report, February 11-March 9,1999,
March 25,1999
Necci to Kenyon, RPN 99-011, Nuclear Oversight Monthly Report, January 7-February 10,
1
1999, February 26,1999
Necci to Kenyon, RPN 99-006, Nuclear Oversight Monthly Report, December 9-January 6,
1999, January 26,1999
Necci to Kenyon, RPN 98-013, Nuclear Oversight Monthly Report, November 8-December 9,
1998, December 24,1998
Necci to Kenyon, RPN 98-009, Nuclear Oversight Monthly Report, October 9-November 7,
1998, November 23,1998
QA open item list
Quality Assurance Audit Report No. A23073, "MP3 Technical Specification implementation
Verification"
Quality Assurance Audit Report No. A22073,"MP2 Technical Specification implementation
Verification"
Nuclear Oversight Audit Report MP-98-A04, " Environmental Protection - Air Quality" Millstone
Station
Nuclear Oversight Audit Report MP-97-A10-07, Millstone Station " Operating Experience
Assessment Program"
Nuclear Oversight Audit MP-98-A01, " Conduct of Operations" Millstone Units 2 & 2 (sic)
Nuclear Oversight Audit MP-98-A03, " Design Control Implementation"
Nuclear Oversight Audit Report MP-98-A06, " Severe Accident Management & Emergency
'
Operating Procedures Unit 2"
Nuclear Oversight Audit Report MP-98-A15, " Measuring and Test Equipment Millstone Station"
Northeast Utilities Nuclear Oversight Audit MP-98-A20, "MEPUPMMS Program"- Units 1,2, & 3
Nuclear Oversight Audit Report MP-98-A23, " Technical Specifications" Millstone Station
Nuclear Oversight Audit Report M2-98-A24, " Millstone Unit 2 Core Reload" Millstone Station .
- Nuclear Oversight Audit Report M1-98-A21, " Conduct of Operations" Millstone Unit i
Nuclear Oversight Audit Report M1-98-A28, " Maintenance / Test Control" Millstone Unit 1
> Nuclear Oversight Audit Report MP-98-A08, " Station Blackout Program" Millstone Unit 2
Nuclear Oversight Audit Report M3-98-A10, " Configuration Management" Millstone Unit 3
i
Northeast Utilities Nuclear Oversight Audit Report ('7 Day") MP-99-A05, "Special Processes"
Surveillance MP2-P-99-025, " Unit 2 Management and Staff Overtime Controls"
Surveillance MP2-99-006, " Conduct of Operations for the period January 9,1999 through
February 3,1999," W. E. Strong and W. D. Bartron to D. A. Hagan, February 10,1999
Surveillance MP2-P-98-064, " Conduct of Operations for the period December 8,1998 through
January 5,1999," W. D. Bartron to M. J. Wilson, January 7,1999
Surveillance MP2-P-98-058, " Conduct of Operations for the period November 6,1998 through
December 4,1998," William E. Strong and W. D. Bartron to M. J. Wilson, December 11,1998
Non-conformance Reports, NGP 3.05
Corrective Program, RP 4
Nuclear Assessment Program, NGP 2.38
Procedure to Stop Work, NGP 3.19
Open Oversight CRs/All Units /All Significance Levels List
CR-01935, Dual Role Valves
CR-7147, QAS Surveillance: Discrepancies Between PMMS and EEQ Master List
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CR-8655, QAS Audit: Conflict Between Electrical Load List and As-Built
.CR-8837, FSARs Require RCS Samples Not Required by Technical Specifications
- CR-8981, TSfor Boron Dilution & Addition is More Restnctive than Other Tech Spec Sections
CR-10107, Electrical Separation
M2-99-0499, MP2 Project engineer exceeded the o'rertime limits, worked 17.5 hrs, person felt
compelled to finish job before leaving for vacation the next day
M2-99-1079, Overtime Policy Violated by Technician
i
M2-99-1181, ." Overtime Control" policy NGP 1.09 was exceeded by vendor personnel on 3/27-
29/99 performing fire watch
M2-99-1360, Supervisor prepared authorization for overtime form without including himself in
j
the list of affected personnel
'
M2-99-1365, CRS involving involving overtime controls issues should address the potential
,
safety implications ID'd in NGP 1.09
M2-97-1102, Auxiliary Feedwater Regulating Valves Not Tested Using Back-up Air
M2-97-1106, AFW Room Heat Load Calculations Have Errors
i
M2-97-1173, Potential CST Inventory Loss Due to Single Active Failure Not Reported in LER in
1991
'
M2-97-2688, Containment Liner Has Severe Coating Failures
M2-98-1085, Containment Liner Paint Not Qualified per ANSI N101.2
'
.
M2-98-2894, Containment Air Recirculation Fans Not Tested in Accordance with Technical
Specifications
M2-98-3101, Assessment of Reactor Protection System Id'd Several Safety Evaluation Screens
Not in Compliance with NGP 3.12 or RAC 12
M2-98-3456, Failure to implement the Requirements of 10CFR50 Appendix B and NU QA
Program (NUQAP QAPs 3 & 5)
M2-98-3559, Action item Assignment was inappropriately Closed Prior to the Actions Being
Completed
Safety Review Committees
Plant Operations Review Committee, OA 3, Revision 4, change 3
- Plant Operations Review Committee meeting minutes, 2-99-020,2-99-021,2-99-022,2-99-050,
2-99-050R, 2-99-051 (Draft), 2-99-052, 2-99-053, 2-99-054, 2-99-056 (Draft)
i
PORC open items
Site Operations Review Committee, OA 4, Revision 2, Change 3
Site Operations Review Committee Meeting Minutes 98-68,98-69,98-71,99-06
Site Operations Review Committee Open items List - Action Request 99001769
Nuclear Safety Assessment Board, NGP 2.02, Revision 16, Change 2
Nuclear Safety Assessment Board Meeting Minutes,' 98-19,98-21,99-01
Nuclear Safety Assessment Board Open items
Meeting Minutes - NSAB-O&M Subcommittee Meeting #98-14, December 4,1998
Meeting Minutes - NSAB-SE Subcommittee Special Meeting #99-06, February 11,1999
Technical Specifications Section 6.5
Student Qualification / Training Status (for Technical Staff), February 15,1999
.
.
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53
ROOT CAUSE INVESTIGATIONS REVIEWED
M2-98-3067, Valve Mispositioning Resulting in Nctice of Violation for inadequate Procedure,
Root Cause investigation
M2-98-3176, Instrument Air Valve was Found Open Versus Tagged Closed as Expected, Root
Cause Investigation
M2-98-3318, LER Root Cause for Negative Pressure Requirements for Enclosure Building May
Not Have Been Conservative, Root Cause Investigation
M2-98-3435, Non-Conservative Assumption in LONF, Root Cause Investigation
M2-98-3839, Pressurizer Spray Thermal Fatigue, Root Cause Investigation
M2-98-3544, Adverse Trend in CRs in Operational Configuration, Control Area Deficiencies,
Common Cause Investigation
j
M2-99-0268, Reactor Coolant System Level increased When Water inadvertently Transferred
'
From SITS, Root Cause Investigation
M2-99-0442, Charging Pump Event During Surveillance Restoration, Root Cause Investigation
M2-99-0304, SFP Water inadvertently Transferred to Clean Waste, Root Cause investigation
M2-97-1171, Unit 2 Floodgate Inspection, Root Cause Investigation
Following is a list of documents in addition to the one enclosed with the previous
j
feeder:
CR Nos, :M2-99-0481, 0451, 0530, 0600, 0630, 0631, 0652, 0268, 0304, 0987, 0046, 0090,
0556,0035,0775,0370,0789,0542
M2-98-0295,1556,1527
,
M2-97-1382
Restart Readiness Report, B17622, dated Jan. 8,1999
Station Procedure: Self-assessment, OA 11, rev 1
Self-assessment for OSTI, Assessment Nos. 2 OPS-SA-98-05, -06; U2-MSA-98-04, -005;
MP21&C 98-3; 2 OPS-SA-97-08; U2-DE-98-017; 2 OPS-SA-98-24,-25,-26.
Unit 2 Work Observation Reports,4* qtr 98, 3* qtr 98,2" qtr 98,1" qtr 98,
Performance Indicators for CRs and AITTs for January and February 1999.
- Northeast Utilities Nuclear Safety Standards and Expectations, rev 0;
Operational Focus Enhancement Strategy;
i
Mid Cycle Corrective Action /Self-Assessment Review, March 24,1999;
Organizational Transition Plan, dated January 14,1999;
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54
OPERATIONS
Surveillance Procedurgtg
. EN 21203, Service Water Flow Through RBCCW Heat Exchangers, revision 5
SPROC EN98-2-23, Operational Testing of 2-SI-651 (DCR M2-98055), IPTE, revision 0
SP 2610E, MSIV Closure and Main Steam Valve Operational Readiness Testing, revision 7,
l
change 6
- SP 2612C, Service Water System Lineup and Operability Test, Facility 1, revision 6, change 1
SP 2612A, "A" Service Water Pump Tests, revision 8, change 3
SP 2612B, _"C" Service Water Pump Tests, revision 8, change 3
SP 26120, Service Water System Lineup and Operability Test, Facility 1: revision 6, change 1
SP 2612C-1, Service Water, Facility 1,~ revision 29, change 3
SP 2612D, Service Water System Lineup and Operability Test, Facility 2, revision 7
j
SP 2612D-1, Service-Water, Facility 2, revision 27, change 9
SP 2612E, Service Water Valve Tests, revision 8
l
SP 2612F, "B" Service Water Pump Tests, revision 0, change 3
SP 2669A, Unit 2 Aux Bui! ding Rounds, revision 26, change 4
,
SP 2610C, Auxiliary Feedwater System Lineup Verification
l
SP 2611C, RBCCW System Alignment Checks, Facility 1
Administrative Procedures
.
DC 4, Procedural Compliance, revision 4, change 6
SPROC OP98-2-08, Unit 2 Restart Following 10CFR50.54(f) Outage, revision 0
U2 OP 200.1, Unit 2 Conduct of Operations, revision 2
C OP 200.1, Conduct of Operations, revision 4, change 2
3
C OP 200.9, Operational Performance Status, revision 1
2-OPS-7.03, Computer Assisted Tagging System Audit, revision 3
' 2-OPS-1.25, Work Observations, revision 10
' 2-OPS-1,32, Locked Valves, revision 4 -
- 2-OPS-1.33, Operations Department Temporary Modification Tracking and Audit Requirements,
,
-
Revision 7
)
NGP 1.09, Overtime Controls for All Personnel at Millstone Station, revision 8
4
DC2, Developing and Revising Procedures and Forms, revision 3
DC4, Procedural Compliance, revision 4, change 5
'
RP 5, Operability Determinations [4 Comm. 3.2], revision 2
RP 16, Trouble Reporting, revision 0
DBS-2326A, Service Water System, revision 1
ODI Form 1.25-36, Safety Tagging: Clearance Preparation and Review, revision 2
ODI Form 1.25-37, Safety Tagging: Hanging Tags, revision 3
ODI Form 1.25-38, Safety Tagging: Independent Verification of Tagging, revision 3
ODI Form 1.25-39, Safety Tagging: Clearing a Tagout, revision 2
ODI Form 1.25-40, Work Control: Pre-Authorization Review of Work Packages, revision 3
ODI Form 1.25-41, Work Control: Authorization and Release of Tagging and AWOs, revision 2
ODI Form 1.26-04, Briefs, revision 0
ODI Form 1.26-05, Communications of Annunciators and Annunciator Response Procedure
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_ _ _ - - _ _
_- __ __ _ _ _ _ _ _
.-
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.
55
(ARP) Usage, revision 0
ODI 1.26-06, Control Room Indication Monitoring, revision 0
ODI 1.26-07, Peer Checks, revision 0 -
' ODI 1.26-08, Operator Procedure Knowledge, revision 0
ODI 1.26-09, Announcing Major Equipment Starts or Shifts
ODI 1.26-10, Tagging Clarifications, revision 2
ODI 1.26-14, Placekeeping, revision 1
ODI Form 1.26-44, Utilization of Three SROs, revision 1
OA 11, Self-Assessment, revision i
U2 OF 5, Unit 2 Work Observation Program, revision 0, change 1
W.C. 2, Tagging, revision 3, change 2
W.C. 9, Station Surveillance Program, revision 3
W.C.-10, Jumper, Lifted Lead and Bypass Control
C AC 3, Post-Maintenance Testing, revision 2
U2 W.C.1, Work Control Process, revision 1
U2 W.C.14, Work it Now (WIN) Program, revision 1
2-UP_-1.03, Unit 210-4-2 Process, revision 2
Operatina Procedures
- OP 2306, Safety injection Tanks, revision 16, change 5
OP-2201, Plant Heat up, revision 27, change 8
OP 2326A, Service Water System, revision 19, change 9
Plant Drawinas
Drawing 25203-26008, P&lD Circulating Water, sheet 1 of 4
Drawing 2520-26008, P&lD Service Water, sheets 2 of 4
Drawing 2520-26008, P&lD Service Water to Vital AC Switchgear Cooling Coil and AC Chillers,
sheet 3 of 4
Drawing 2520-26008, P&lD Screen Wash and Hypochlorite, sheet 4 of 4
Drawing 25203-30001, Main Single Line Diagram
,
Drawing 25203-26005, P&lD Condensate Storage & Aux Feed
Drawing 25203, P&lD RBCCW System RBCCW Pumps & Heat EXCH.
Drawing 25203, P&lD RBCCW System Spent Fuel Pool & Shut-Down Heat EXCH.
Drawing 25203, P&lD RBCCW System CNTMT. Spray Pump & S.I. Pump Seal Coolers
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56
. Self-Assessment
]
2 OPS-SA-99-18, Unit 2 Configuration Control items Self-Assessment - Based on Unit 3 OSTI
J
Lessons Learned
Millstone Unit 2 Operational Readiness Report (dated November 17,1998)
OF-11, Self Assessment
2 OPS-SA-99-18A, Configuration Control Events
Condition Reports
CR M2-99-0515, Maintenance cut a half inch main steam line outside the tag-out boundary.
CR M2-99-1082, Safety injection tank vent valve was found open while it was red tagged closed
under clearance 2-267-99.
CR M2-99-1113, Maintenance personnel cut into an instrument air supply line
. Q_ondition Reports Documentina Valve Alianment Errors
i
Events that occurred during the OSTI inspection:
.CR M2-99-0970, Water was unexpectedly drained to the east condenser sump because a two
inch drain line valve was left open instead of closed. The inadequate restoration followed a
'
modification to the turbine building fire sprinkler system. The apparent cause was personnel
error in not recognizing a vent valve on the fire sprinkler valve should be confirmed closed.
CR M2-99-0971, A valve lineup for the fire protection system was inadequate in that all of the
required valves were not included in the lineup (Ops Form 2618K-1) after the system was
modified. A contributing factor to the spill of fire water documented in CR M2-99-0970
(discussed above) was inadequate updating of drawing 25203-26011 after a modification was
made to the turbine building fire sprinkler system.
- CR M2-99-1025, Tagging Clearance 2-0158-99 indicated that the restoration of certain post
accident sampling system (PASS) valves would be performed under lineup CHEM Form 2804K-
11. This lineup did not include all the valves which were required for restoration from the
clearance.
CR M2-99-1071, Valves added by a modification to containment sump valves (2-CS-16.1 A & B)
had not been added to the containment integrity lineup nor to the Technical Requirements
Manual containment isolation valve list (section 5.0, page 11.5-8).
' CR M2-99-1078, Change 8 to the containment integrity lineup, SP 2605A was processed on
March 21,1999. This change added new valves associated with DCN DM2-0300605-98, DCR
j
' M2-97037. The revision of 2605A-1 performed in preparation'for Mode 4 on March 20,1999,
)
- did not contain the new valves,
j
,
in the month prior to the OSTI, the licensee issued the following condition reports which also
I
documented problems with the implementation of activities related to valve and breaker lineup
.
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processes.
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- CR M2-99-0424, throttle positions for some throttle valves on the chilled water valve lineup
. (OPS Form 2330C-1, Rev 15) did not match the positions listed in the more recent revision of
' chill water procedure OP-2330C, revision 11, change 4. Procedure change did not get
incorporated into the valve lineup.
CR M2-99-0471, Valve lineup (Ops Form 2304A-1) showed the position for the volume control
tank (VCT) outlet header to the sample system isolation valve (2-CH-116) to be closed. The
system.P&lD (25203-26017, sheet 1) showed the position of this valve to be open. Having the
normal position for this valve as closed would require personnel to open it in a post-accident
situation in order to route post accident sampling system (PASS) effluent back to the VCT.
Condition Reports Documentina Eauioment Taaaina Issues
CR M2-99-0515, Maintenance cut a half inch main steam line outside the tag-out boundary
which had been established to support the modification work. Operations had to close four
. additional valves to stop the flow of water form the cut line.
CR M2-99-1082, Number 4 safety injection tank vent valve nitrogen supply stop,2-SI-842, was
found open while it was red tagged closed under clearance 2-267-99. The valve disc was so
hard against the backseat that two people independently incorrectly determined it was shut.
CR M2-99-1113, Maintenance personnel cut into a instrument air supply line in the room
between the condensate storage tank (CST) and the condensate surge tank without the line .
being tagged out. The air line was being cut to replace valve 2-CN-241, hotwell make-up from .
CST.
Maintenance and Surveillance
Maintenance / Surveillance Procedures
TQ-1, Personnel Qualification and Training,
-
U2 OA 5, Unit 2 Work Observation Program,-
U2 WC 1, Unit 2 Work Control Process,
i
WP 28001, AWO Preparation and Work Scheduling,-
2-Ul-1.03, Unit 210-4-2 Process,
RP 16, Trouble Reporting,
U2 CBM 105, Preventiva Maintenance Program Changes and Deferrals for MP2,
CBM 107, integrated Preventive Maintenance Program,
MP 2701J, Preventive Maintenance,
C MP 701, Conduct of Maintenance,
- OA 10, Millstone Maintenance Rule Program,
OP 2264, Conduct of Outages,
COP 200.9, Operational Performance Status,
' ODI 1.39, Operations Review Board,
MDI 2-1, Attachment 9, Departmental Expectations, Pre and Post Job Brief Guide,
OA 11, Self Assessment,
OA 5, Work Observation Program,
.
58
OA 8, Ownership, Maintenance, and Housekeeping of Site Buildings and Facilities and
i
. Equipment.
- IC 2438, Preventive Maintenance Program,
. U2 WC 9.1, Surveillance Program implementation,
WC 9 Station Surveillance Program,
C WPC 3, Post-Maintenance Testing,
C WPC 4, On-line Maintenance,
NOQP 4.08,. Determination of Quality Controls for Quality Activities
OM 1, Outage Management,
OM 2, Shutdown Risk Management,
WC 18, Foreign Material Exclusion and System Cleanliness,
WC 2, Tagging,
MP-20-WM-SAP 02, On-Line Maintenance,
MP-20-WM-FAP02.1, Conduct of On-Line Maintenance,
2601J, Completion of "C" Charging Pump IST Testing,
AWOs
M2-99-03175, Hydrogen Purgs Air Accumulator for 2-EB-92
M2-97-01191, "B" DC Switchgear Room Chiller (Vital Chiller)
M2-98-06835, "B" Control Room Air Conditioning Compressor
M2-98-11470, #4 Safety injection Tank Vent to Containment Valve Assembly
M2-98-06629, "B" Turbine Building Closed Cooling Water Heat Exchanger
M2-97-01163, Chilled Water System
M2-96-03285, Replace Valve Stem IAW DM2-00-1690-98
M2-97-06220, "A" Condensate Motor Overhaul,
M2-99-01562, X27 Station Air Compressor Aftercooler,
Maintenance Rule Corrective Action Plans
service water system
chilled water system
480 volt ac load center system,
480 voit ac motor control center system
control room air-conditioning system
engineered safety features actuation system
PARTIAL LIST OF ENGINEERING DOCUMENTS REVIEWED
Surveillance Procedures
SP 2609A, EBFS and Control Room Ventilation Operability Test, Facility 1
SP 26098, EBFS and Control Room Ventilation Operability Test, Facility 2
SP 2609C, Enclosure Building Operability
- SP 2609F, Control Room Ventilation System Filter Testing, Flow and D/P, Facility 1
!
x
.
-59
Ooeratina Procedures
OP2315A Control Room Air Conditioning System
Plant Modifications /MMODs/MSEEs
DCR M2-97-0-12 (EWR M2-96-191) Single Failure of CRACS Damper 2-HV-210 & Permanently
- Closing Crosstie Damper 2-HV-213
DCR M2-97-042 (EWR M2-96-133) Intake Structure Ventilation Modification
DCR M2-98105 (EWR M2-98-174) Replacement of Pressurizer Spray Piping
DCR M2-97050 Modification of ESAS Undervoltage Sequencer Module
DCR M2-97011 EDG Pre-lube, Slow Start and " Ready to Load" alarm modification.
DCR M2-98095 Turbine Driven AFWP Redundant Power Supply
DCR M2-98073 Cross Connect Piping Between CST and Condensate Surge Tank
DCR M2-99004 Safety injection Tank Nitrogen System Modification -
MMOD M2-97531 Relocation of Differential Relays for 4160V Switchgear
MMOD Fan 158 HELB Interlock Modification
DCN DM2-00-0074-99 EBFS Charcoal Tray Bolting
DCN DM2-00 2053-98 Overpressurization of SDC Line
DCN DM2-00-1690-98 TDAFW Governor valve
DCN DM2-00-185-99 Condenser Tube Shields
DCN DM2-02-1411-98 Relay Replacement
DCN DM2-00-1755-98 Service Water Pump Motor Replacement
DCN DM2-00-0215-99 RPS Fuse Replacement
DCN DM2-00-0356-99 Lighting Panel Wattage Reduction
Condition Reoorts
M2-97-0532 Loop 2B Flow Transmitter input Calibration Change
M2-97-2810 DCNs issued Without Adequate Bend Radius Information
'M2-97-2946 Leak Tightness of LPSI Not Verified for Post-LOCA
- M2-98-0059 Post LOCA Boron Precipitation Control Subject to Single Failure
- M2-98-0437 Insufficient Cable Bend Radius
M2-98-0451 Loss of Service Water During LOCA
M2-98-0474 Insufficient Cable Bend Radius
M2-98-1392 Operability of Motor Driven AFW Pump
- M2-98-1430 Operability of SIT Tanks When Filling, Draining, Adding, Venting
M2-98-1431 IST Acceptance Criteria May Not Assure Equipment Performance
M2-98-1526 Containment Spray Pumps could Be Adversely Affected
M2-98-1527 EDG Load Sequencing With Simultaneous Start of Pumps
M2-98-1605 Combined ECCS Pump Minimum Flows Could Result in Deadheading
l
M2-98-2736 Boroscope inspection of Check Valve
i
M2-98-3303 Design Cales TS Requirements Differ from Pump Performance
i
)
u
.
e
60
M2-98-3526 Post SBLOCA Nitrogen Intrusion to RCS
M2-98-3774 SFP Siphon Breaker Hole Sizing and Location
M2-98-3852 Discrepancies Between MEPL, PMMS and Electrical Schematic
l
M2-99-0643 Discrepancies Between Plant Drawings, Calculation and As-Built ~
M2-99-1122 Basis for use of HPSI pressure instruments in EOP 2532
. Calculations /Supportina Procedural Chanaes/ Modifications
- 92-030-1259E2 Rev. 2 RWST level-Setpoint Analysis L-3001,L-3002, L-3003, L-3004
S-01228-S2 Rev. 2 M2 EOP Setpoint Documentation
CE NPSD-1009, Rev; O l&C Engineering Limits and Bases in EOPs Uncertainties
99-ABB-02825-E2 2 Tech Spec Action Value Basis Document- RWST Volume
98-ENG-02558M2 Rev 0 Determination of Minimum Submergence Criteria RWST
97-ENG-1768E2 Rev.1 Pressurizer Pressure Loop Uncertainty
1
97-122 Rev. 2 ECCS Flow Analysis for Millstone Unit 2
)
PA XX-XXX-1007-GE Rev.1 LPSI Flow Loop Accuracy
i
PA XX-XXX-1006GE Rev.0 HPSI Flow Loop Accuracy
S-01901-S2 Rev. O Development of RCS PT Curves for use in SPDS/EOPs
97-DES-1739-M2 Confirmation of Availability of Fire Water as Backup to AFW (EWR 2-94-0262)
System Readiness Reviews
Reactor Building Closed Cooling Water System
Containment Spray System & Refueling Water Storage Tank
Safety injection Tanks and High Pressure Safety injection System
' Auxiliary Feedwater System
4.16 kV Electrical System
q
125 Volt DC System
'
inadequate Core Cooling System
Control Room Heating and Ventilation System
Miscellaneous
L
MEMO TS-97-256
Concurrent Operation of RCPs and LPSI Pump for SDC
,
.
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.
Q
ATTACHMENT 1
Slides used at April 7,1999 Exit Meeting
a
i
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1
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t.
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Inspection Objective
y
c'
OPERATIONAL SAFETY
g^ d
TEAM INSPECTION (OSTI)
8
" T pr vid urr at information to the
o
Restart Assessment Panel by evaluating
o
"'
'
NRC Exit Meeting
g.j and management programs to support a
- 5a
April 7,1999
safe restart and continued operation of
Inspection 50 336/99-04
Millstone Unit 2
..n
.
OSTITeam Assignments
inspection Schedule
j e Onsite preparation
-
14:01
(merch 14,1ose)
l ,.:h ]
a In-office preparation
g
g
(werch s.12,1oes)
NNl
l
l 71.2 l
l
l
g,j u Two week onsite inspection
I- I'rhll =llsIBElT= IFi=1
'
(March 1526,1999)
_m.
n
,
~~,n
.
sunmnum m cwure
Assessment Areas
,1. Management ProCrameAndependere Oversight
' "h efe
'
3
C
a SIL 8 Work Planrdng and Control
2. Operations
@
u SIL 7. Operator Work .Arounds & Control Roorn
De6ciencee
.y S. Engineering and Technical Support
j e SIL 13. Operator Performance
a SIL 20.7. Pressure Locking of Velves
4. Maintenance and Surveillance
a SIL 53.1. Sir.gle Failure end ECCS
-u s een
s
mwicen
e
1
!
_ _ _ _ _ _ _ _
_ _
___-_ _ - _ _
e
w
Management Processes
AppropetMe management proce-n twve been
eeanbNen.d and are Amcdoning adequately to
,
--
., -; support a eete plant roesert and consnued
Management
c%
op.r. don
'
Programs / Independent Oversight
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,
,,,,,eme, h,, e.,,,,,,hed ,_,, ,,,,,,, , ,o,, ,,,,
oa
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.ccanon.
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- [ s Ttw operanonal Readiness Pian demonstrated resotusen or
p,
. poenn.nc. . .
. u r. gem.nio.mor
md .trong =*.mont m em.,gog
pm.e ..
-ui n
.
-= > n
.
Management Processes (cont)
Corrective Actions
'
' 8'
'"
'8
a unnagement has toen respoestre e employee concems
.
3 accepenMe to supportplant teetert
3
'
I e Adequete etsmno hee toen proved for recowry (oneme of
'
panie stan we. touw contmand in accordance wm NRC
e Plant manegement inn toen a%amly Warmd m the
guidestwo)
o
conecke acton program
- e oussay Asswance has twen enecoway meegreed una em une
y a The aveshold for includbng usues inen the conectw actens
orgenarason
program a low
e The eter-department communicahon nwchenome are
e The quaMy o, recongy performed root came snelrus were
.ppmpnam m eupport op.raan or e. una
gad
hama== m oen
u.a.uu i can
.
Corrective Actions (cont)
Self-Assessment
'a m ,'c,=,aT, ,la^:::",at,=a.,m,.d
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remad a resset reeduwee
~. ; e The setassessment processee appeared to to functoring
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a The =taprown=re pingisms tan teen ee.cthe
khases uns 3 05r1
ll
hhanesUhs B En
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2
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Independent Oversight
independent Oversight (Cont.)
i
,
i
The Nuclear Overnight Orperdzedon hee pnwided
j
f -- . _-..JJ performance mesesements and hee
' 3 m Nuchas Ovemgh.taudt Andinesweie revowed and Anengs
"'
restartimpacatens have tun pmpany
% offecdvelyidentf#ed erees forimprovement,
- 8h P.C#'88 Ph
I
'
.ddre .ed
e The Nucleaf Overe6ght Orgaruzanon was effectwo in
O
E , mee rsight reports provated usehA ed
e NuckerOve
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,,tas, = ,';; y a go,,*"'n=*
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.nd w o,
n. n .ni,er,.mance and
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d0$ e The Nuclear Overs'Oht Orgaruzabon's invokoment m
em.r.non . mannsnanc.=urv.s.nc. .nd .nsiaeenno ha
e. n v wine
3
a mmeis.sacert
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n eemsmaacan
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Quality Review Committees
The Plent Operadone Review Committee,
Sseden OpereGons Review Commelsee, and
.ol.
I
the Nuclear Sellety Aseessment Board comply
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O erations
P
a J with en Technicet specincecone
g-
muswnence
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s Stabon and Platt Operacons Revew Commatoes
conduced mquired samty reviews appropruimy
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g
a The Nuclear Safety Assesamord Boanf was eRecuve in
paidmg phet samty overught
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Opadons (cont)
Conductof Operations
- Nr'au"n "**" '"* ***' "" * '"*
_ The conduct oroperecone was acceptende
a
,;y
a Control toard awareness and emurrete response were
e stafang treet metTechnscal Speericabon Requirements
@
oenesar and
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e ~ro,ne
,.. wore .,es
.dh
n.nsi,sm
reghements
't
e opwstors acoresy asentswd end conoced eenconce.
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Procedure Quality / Adherence
Equipment Status Controls
opweene procedure queury wee genereny good
l
operator's procedure adherence was approprinne
_ Controle for esenbushing equipment status were
1
y
'., ; 1 acceptable
a genom ve ow.eng pr c
,e.revgodwe,.
chnuty sound
a The equMe4 chance pograin me genn8y 08ectm
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. =m _ m,_. _e .e, ._p.te, ._ed
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documersed
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n.aemm w. I oen
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Training and Qualifications
i
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punt operenons otoff had received approprum
Engineering and Technical
'
q;
'
treening
S
Support
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. nego ,ed 0,
,sou =.oon
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e Tme.g
mod =.t,..w...,,,o
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Plant Modifications
Plant Technical Support
l
The punt modencecon program was
The Eneineering and rechnker support
approprutely contraned and implemented
. . Deparanents providat emeiy and etInstive
,
'
. . k eupport to the une orgentzeeans. The becksoa of
e Dateded pecess lor design changes
O
engineering work wee property priorlet2ed for
8
8
feeart
e The pennenent meagn change packages,inctA .e me.ty
sevows and poet modecation t-sting, were enhJesar
e Knowledgest. System Engewers
!
.. . sound
-
l
4
- ^9 m Proposed phnt modecanon desotrae were appropnete
'" e E#ectve s@ port for emergott plant asues
a Tempm,y modmcanon program cortroh are enecthm
o opmbety mormmations were techrecas, sound
l
f
u soon
n
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m
4
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,
Plant Technical Support (Cont.)
Engineering Programs
i, . The m. mon er conomon toporte we. e-ouon and en.y
-.
me enginewing progreme wm errecovery
- a The syvem Reedmess Revowe were compretenswo
D
e Pfard drawings reflected plant doesgn and design change,
e The vendor equipmentlechntsiir*>rmation was properly
updated
,
' d
s Phrd @ m W cmbd end e
catubscons were genersW appropnate
num waeen
a
mmm maoen
u
Engineering Programs (Cont.)
Maintenance and Surveillance
a
9. rh. .mm.u nde .d
n docu,nen. ,ev- were
,,
<
"<
wchntasy so.w
8
e opereano expeneace evaut=n= were v= rough
8
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- N.$
kikf
3
imm wroen
rr
um uuseen
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I
Conductof Naintenance Activities
Planning and Scheduling
unintenance ecovtsee asemed wm genuouy
good
Ment schedule goele were not met due to
, y;
. ;b emergentleaves
a Pmcochase cpeHty and adtwrence were generaW approprute
' Work planning peChego que#ty wee good
a
D
U
e Waregement overaght of sold actMtes was effectwo
m Emergers inause wece provereng accurew schedunne end
a Quality of maaleenance work was generany good
,.
,
' ' ' ,
'
a work pisaning process knprwoments were penned
,
,,
a Work plannm0 Peckages and shp tets quemy were
appeopriate
wm uu s can
a
wm.m > oen
m
5
f.
1
/
M
i
Plant Material Condition
Preventive Maintenance
The plant meterial cor# don wee accepteNe
PM program wee necepteNe
'
s Backlog of momenarce activmee had been priortrod
' -
a
~ a PMs required %r restartwere completed
'
@
m impact en oporstone assessed
g
O
a
e Condition based mondormg procedure was recortly leeued to
O
e Housekeeping and equipment serage wre gewracy
improve tw PM program
appropnate
, j :. t
m.{ e PM procedureswere generally ecceptatWe
gy e Observed equipment condmoriwee accepenbee
g
w o.n
ii
-w oon
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Surveillance Testing
OSTI Conclusion
SurwMence teedng program wee accepenNe
j j e The OSTI furjings are one input used by
.' S . swvenance wenng proceduree =re necepmo"
~! '
the NRC Restart Assessment.Tnel(RAP)
g
. surve4=nce um procedwe edherence was good
g
in making a restart recommendation to the
O.
. tecteucere perionung wenng were quan.d .nd
'
Commission
gj e The OSTI conclusion is contingent upon
kaa**o'**
f,
the licensee's successful completion of
. Pr wm nr.nnes a me coordin.imn wie operwmn. =s m
'
those items identified as required prior to
restart
w.
w
w een
,,
OSTI Conclusion (Cont.)
P
The OSTI has concluded that plant
hardware, staff, and management
g
programs are ready to support a safe
a
plant restart anti continued plant
'
. . ,
operation of Millstone Unit 2
6