IR 05000271/1986013
| ML20206M491 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 06/20/1986 |
| From: | Cowgill C, Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206M480 | List: |
| References | |
| 50-271-86-13, NUDOCS 8607010200 | |
| Download: ML20206M491 (29) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
86-13 Docket No.
50-271 License No. DPR-28
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Licensee:
Vermont Yankee Nuclear Power Corporation RD 5, Box 169, Ferry Road Brattleboro, Vermont 05301 Facility:
Vermont Yankee Nuclear Power Station Location:
Vernon, Vermont Dates:
June 2-6, 1986 Inspectors:
J. Berry, Senior Resident Inspector, Shoreham D. Trimble, Resident Inspector, Calvert Cliffs J. Schumacher, Reactor Engineer P. Bissett, Reactor Engineer R. McBrearty, Reactor Engineer H. Gray, Lead Reactor Engineer i
J. Cioffi, Radiation Specialist Pods Approved by:
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~Curtis J.
ow 1, Chie, TMI-2 Project Section Date Emergenc par ne and Radiation Protection Branch
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Thomas C. Elsasp r A hief, Reactor Projects Section Date
3C, Projects B Wch 3 Inspection Summary: Inspection on June 2-6, 1986 (Report No. 50-271/86-13)
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Areas Inspected:
Special announced team inspection at the Vermont Yankee facility of the following areas: Management Controls over outage activities, System Restora-tion, Quality Assurance, Preservice Inspection /Non-Destructive Examination activi-ties, Operator Readiness for Restart, Outage Health Physics.
In addition, the in-spectors reviewed previously identified items concerning outage activities and con-
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ducted comprehensive plant tours.
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Results: No violations were identified; however, the inspection team did identify noted licensee strengths and weaknesses regarding outage activities (weaknesses require further licensee attention and written response).
These strengths and weaknesses are summarized in transmittal letter Appendices A and B, respectively.
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Other areas requiring licensee attention included: operator training in Emergency Operating Procedures (EOPs) (Paragraph 5.3), formal review of surveillance activi-
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ties by the operations Quality Group manager (Paragraph 4.1), Radiation Work Permit (RWP) preparation (Paragraph 7.3), and personnel certification of receipt inspec-tors (Paragraph 6.5).
Overall, the team concluded the facility was ready to resume power operation upon completion of licensee planned testing and close out activi-ties and correction of NRC observed deficiencies regarding operator training in
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the areas of E0P's and outage modifications.
t 8607010200 860623 PDR ADOCK 05000271 G
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j TABLE OF CONTENTS PAGE 1.0 Scope................................................................
2. 0 Management Oversight of Outage Activi ties............................
2.1 Outage Organization.............................................
2.2 Thor 9e5ress cf 9evi?c.
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2. 3 Effectiveness of Tracking Systems...............................
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2.4 Contractor Oversight / Control....................................
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2.5 Conclusions.....................................................
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3.0 System Restoration...................................................
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3.1 Milestone Review............................................
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3.2 General Restoration Activities..................................
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I 3.3 Outage Modifications.............................
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3.4 Hangers Reinsta11ation Contro1..................................
3. 5 Conclusion......................................................
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4.0 Quality Activities...................................................
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4.1 QA Surveillance and Audits......................................
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l 4.2 Design Contro1..................................................
4.3 Maintenance Activities..........................................
i 4.4 Management Involvement in Assuring Quality......................
i 4.5 Conclusion......................................................
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5.0 Operator Readiness for Restart.......................................
5.1 Maintenance of Operational Ski 11s...............................
5.2 System Design Cb:nges and Modifications.........................
i 5.3 Emergency Operating Procedures (E0P)............................
5.4 Conclusion......................................................
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6.0 Preservice NDE Activities............................................
J 6.1 Recirculation Piping Replacement................................
6. 2 Followup of Allegation Regarding Recirculation Piping j
Replacement.....................................................
6.3 Recirculation Piping Replacement Preservice Inspection (FSI)
l Data Review.....................................................
6.4 Condensate Storage Tank (CST) Repair............................
3 6.5 Personnel Qualification / Certification Records of Receipt
Inspectors......................................................
6.6 Conclusion......................................................
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7.0 Outage Health Physics................................................
7.1 Management Controls and Staffing................................
1 7.2 Implementation of the Radiation Protection Program..............
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7. 3 External and Internal Exposure Controls.........................
7.4 Outage ALARA Program............................................
7.5 Conclusion......................................................
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8.0 Plant Condition / Facility Tours.......................................
9.0 Action on Previous Findings...................................
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10.0 Persons Contacted....................................................
4 11.0 Management Meeting...................................................
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DETAILS 1.0 Scope During the period June 2 - 6, 1986, a team of seven resident and and region-based inspectors lead by two Region I section chiefs, performed.3 team in-spection of the facility.
The purpose of the inspection was to assess the licensee's readiness for operation following the extended refueling outage.
The areas reviewed during the inspection included overall management controls of pipe replacement and modification activities, system restoration, quality assur7n.e, oportter training, oretervice incpection/ welding activities and radiological controls.
2.0 Management Oversight of Outage Activities The inspector conducted a review of those activities which related to overall managerial control of the outage.
This included interviews with cognizant
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management personnel as well as attending daily outage meetings and a meeting of the Plant Operations Review Committee (PORC).
Discussions were held with additional members of the plant staff and Yankee Atomic QA personnel to assess (1) effectiveness of the outage organization, (2) thoroughness of management reviews, (3) effectiveness of tracking problems to resolution, and (4) ade-quacy of contractor oversight / control.
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2.1 Outage Organization Prior to the outage, the licensee visited utilities that had completed recirculation piping replacements and used their lessons learned in out-age planning.
The outage organization was established with this infor-mation in mind.
At the beginning of the outage, an " Outage Manual" was issued (October 3, 1985) which described the (1) outage organization, (2) outage work scope / design changes, (3) responsibility assignments for major tasks, (4) expected contractor listing (993 contractor employees were expected to be utilized), and (5) the outage schedule.
The manual was routinely updated throughout the outage, mostly for schedule updates.
A task force was organized under a Project Manager for the sole purpose of managing the recirculation piping replacement. The Project Manager reported directly to the Vice President and Manager of Operations.
The task force
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included personnel to provide engineering oversight / support, construction oversight, and administrative support.
A dedicated group of QA personnel reporting to the director of QA, Yankee Nuclear Service Division (YNSD),
were assigned to monitor the recirculation piping replacement activities.
Outage activities not specifically associated with recirculation piping replacement were managed by an Outage Manager (the Operations Superin-tendent) who reported directly to the Plant Manager.
The Plant Superin-tendents reported to the Outage Manager.
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A daily meeting was held between the Outage Manager, Plant Manager, the Superintendents / department heads, and a representative of the recircula-tion piping task force.
Two NRC team members attended these meetings during the inspection period.
The meetings were of approximately 45 minute duration and were an effective means of (1) communicating plant
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status / outage activity status; (2) identifying problems and assigning responsibility for resolution of those problems; (3) determining if i
problems warranted separate meetings / discussions; and (4) prioritizing competing problem areas.
The Outage Manager was assisted by an outage planner (this individual produced / updated outage schedules) and a Startup/ Restoration Group Effort (SURGE) team.
SURGE was supervised by an operations shift supervisor dedicated to the task and included vendor engineering personnel.
SURGE acted as a collection point.for all outage work requirements.
The group prepared punchlists of outstanding activities to be accomplished to meet pre-established outage milestones.
An NRC team inspector met with the SURGE manager and discussed the various informational sources utilized by the group in formulating punchlists. The group appeared to be using all available sources.
These included the commitment status list, PORC Follow Item list, outstanding nonconformance reports (NCRs), plant pro-cedures, technical specifications, and outstanding maintenance requests.
Several plant supervisors indicated that SURGE had been very effective to date.
This was the first outage in which the SURGE group was utilized.
The operations supervisor felt a strong sense of responsibility in this
area.
Because SURGE was managed by a shift supervisor, the operations supervisor had increased confidence that items needed for operability would be identified.
The operations group ultimately makes final as-sessments of system operability, i
In addition to daily outage meetings, pre existing mechanisms for iden-tifying problems to management for review continued to function as in-
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tended.
For example, core spray nozzle cracking and the ensuing repair were raised to management attention by means of a probable reportable occurrence (PRO), Installation and Test Procedure, Licensee Event Report (LER) (86-05, dated 4/28/86), and Engineering Design Change (EDCR 85-1)
with associated changes.
Similarly, N2 nozzle welding problems were brought to management review by means of engineering changes and an NCR
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(86-53).
2.2 Thoroughness of Review
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The licensee employed the services of outside activities to provide ad-ditional review of activities essential to the recirculation piping re-placement.
The licensee obtained third party technical reviews of stress calculations in areas such as recirculation piping stress and hydraulic analyses to confirm the validity of NSSS supplier calculations.
An engi-neering consulting firm was engaged to provide general assistance to corporate officials on resolving technical issues associated with piping replacement.
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The Plant Operations Review Committee (PORC) utilized consultants with additional expertise in their review of more complex technical issues.
For example, during a review of piping documentation procedures and the safety analysis in the June-September 1985 period, information from the vendor, EPRI (Electric Power Research Institute), and the Corporate Chemical Engineer were utilized.
An NRC team member attended a June 3, 1986 meeting of the PORC chaired by the Plant Manager.
The committee notably sought to identify and address the root cause of an improperly installed drywell thermocouple (NCR 86-84).
All members present actively participated in group discussions.
Interviews with committee members and the PORC secretary indicated that agenda items are typically routed through and reviewed by affected super-intendents and department heads prior to presentation to the PORC.
Meet-ings are generally of relatively short duration (around 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />).
The committee makes an effort to limit the number of complex issues on any given meeting agenda.
The flexibility afforded by technical specifica-tions for use of alternate members is utilized by the licensee to spread PORC time obligations over a large group of people. In combination, these practices appear to minimize the overburdening of committee personnel.
2.3 Effectiveness of Tracking Systems The effectiveness of the SURGE group punchlist system was noted above.
The licensee also uses (1) a follow items list to track PORC action items; (2) a commitment status list to track a variety of action items (e.g.,
NRC commitments, plant incident reports, and implementing directives);
and (3) an NRC tracking system.
Responsibilities for action are approved by management (e.g., superintendent level) prior to entry on these sys-tems. Those responsibilities are then clearly assigned.
Twice per year the PORC follow items list is reviewed by the PORC. The backlog of NCRs appears to be at a manageable level (34 outstanding).
NCRs receive a management review prior to final closecut to ensure all items are com-pleted or, where appropriate, entered into an appropriate. tracking system.
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2.4 Contractor Oversight / Control QA personnel were dedicated to the recirculation task force and were ef-fective in detecting and pointing out to licensee management problems regarding contractor bypassing of hold points, poor contractor supervi-sion of welders, and problems with purge dam installations.
These con-cerns were ultimately described in a March 3,1986 memo to the Director of QA, YNSD.
Beginning in December 1985, licensee management began to seek corrective action from the contractor for these discrepancies.
In-creased licensee oversight and increased QA surveillance of the contrac-tor were initiated including 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> drywell coverage.
At one point, all work was halted and retraining on hold points was provided to con-tractor personnel.
A strong disciplinary policy was implemented. The Vice President and Manager of Operations were intimately involved in
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seeking corrective action from the contractor.
Although delays were experienced due to these contractor problems, final work product accept-ability was obtained.
As part of reviewing QA effectiveness in identifying recirculation pipe replacement problems, discussions were held with the Director of QA, YNSD, and the Operations Support Supervisor.
The licensee described the re-selts of an internal evaluation they had completed in 1985 on overall QA effectiveness within the company.
The company is taking action to improve deficient areas noted by the evaluation.
A need for improved communications between QA and operational management was one weak area identified by the evaluation.
Discussions with personnel involved with the recirculation piping replacement showed that direct, frequent and effective communications existed between QA personnel monitoring the piping replacement and the replacement project manager.
2.5 Conclusion The review of selected issues showed that mechanisms were in place and were being properly used to bring significant problems to management at-tention.
Plant management and the PORC conducted adequate reviews of the problems selected by the inspector for this assessment.
Management initiated corrective action, and mechanisms were in place to effectively track implementation of those actions.
Additionally, the licensee took effective action to correct poor piping contractor performance in the area of craft supervision during the recirculation system piping replace-ment project.
3.0 System Restoration The inspector reviewed various aspects of the licensee's system restoration efforts.
The review included; (1) milestone review and tracking methods; (2) general restoration activities including maintenance activities, procedure revision review, and contractor training; (3) design change methods and outage modifications; and (4) hanger control program review.
3.1 Milestone Review The inspector reviewed the system established by the licensee for moni-toring and controlling outage progress.
The licensee established six major milestones to accomplish this goal.
These milestones include ves-sel fill, induction heating stress improvement (IHSI), fuel load, hydro-static testinC, integrated leak rate testing (ILRT), and startup testing.
These efforts are monitored by the SURGE team.
Each milestone is tracked using a punchlist maintained in the control room containing the necessary plant systems, interface equipment and testing requirements that must be completed to meet the specific milestone.
Each punchlist also con-tains various appendices which track the specific work packages and maintenance requests that must be completed to support meeting this mile-stone.
This system ensures that all required work for each milestone
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is clearly assigned and that no safety-related equipment is bypassed during the reinstallation effort.
The inspector determined that the system is effective because the licensee has met each milestone close to schedule with no adverse impact on safety.
3.2 General Restoration Activities The inspector reviewed the following safety related maintenance requests (MR): MR#85-1200 - Motor Operated Valve (MOV) Maintenance on V10-18; MR#86-0851 - Inspect Residual Heat Removal (RHR) Valve 46A; MR#86-0520 -
Remove Internals of RHR 46A for Pipe Inspection; and MR#86-0081 - X30 Penetration Rework.
The inspector verified the accuracy of the licen-see's tracking methods by reviewing both the incorpora' ion of these MR's into the appropriate punchlist as well as handling in the MR tracking system.
These MRs also were reviewed for completeness with respect to proper QC hold points, QA review, and retest requirements.
Additional non-safety related MRs were spot checked for applicable retest require-ments.
With respect to MR#85-1200, a review of OP 5220, Rev. 7, "Limi-torque Operator Inspection" was conducted.
This procedure is used by maintenance personnel to perform maintenance and inspection of the limi-torque motorized valve operators.
The inspector verified that this pro-cedure contains proper controls including checklist and testing criteria to ensure proper restoration of MOVs. No discrepancies were noted.
The inspector reviewed a licensee identified problem concerning crossed instrument lines to the recirculation loop "A" flow element which was detected during a test run of the "A" recirculation pump following piping replacement.
Licensee investigation into this matter showed that flow element sensing lines replaced during this outage were properly installed.
However, a hand over hand check of the instrument sensing lines identi-fied that the high/ low sensing lines were crossed at the instrument rack outside the drywell. These lines had apparently been crossed during original plant startup.
The inspector reviewed flow and thermal parameter data for the previous operating cycle to assess its accuracy.
GE evaluations of themal para-meters and predicted flow were consistent with actual plant values.
Ad-ditionally, flow transmitters and associated instruments were routinely calibrated and demonstrated operable in accordance with plant procedures.
The inspector had no further questions regarding this item.
The inspector reviewed selected Instrument and Controls (I&C) Test pro-cedures to confirm that the procedures were revised to reflect changes resulting from system modifications.
Operating procedures (0P) 4354,
"RHR Subsystem A/B Logic Test", Rev. 3 and OP 4100, ECCS Integrated Automatic Initiation Test", Rev. 11, were revised to reflect the deletion of RHR crosstie valves.
Applicable wiring diagram changes were also verified by the inspecto _
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The inspector reviewed selected contractor training and qualification records to confirm that Mercury Control Company personnel had received proper training prior to performing outage work.
After completing lic-ensee access training, workers receive training from Mercury Quality Control in Safety, VY regulations, Health Physics, and Quality Control.
Additionally, job specific training is conducted.
The inspector noted that licensee personnel actively monitored Mercury training programs to ensure adequacy, and that these programs were modified to reflect lessons learned.
The inspector concluded that training for workers and supervi-sors is thorough and detailed.
3.3 Outage Modifications The inspector reviewed selected work packages performed by Morrison-Knudsen (MK), the general contractor for recirculation piping replace-ment, during the current outage to determine that restoration was pro-perly accomplished and that system drawings were updated to reflect as built conditions.
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The inspector reviewed activities associated with interface reinstalla-tion.
The licensee created a computerized tracking system to ensure all interface equipment (small bore piping, electrical interface, hangers, whip restraints, etc.) was properly controlled.
The system listed steps from MK work packages that removed interface items next to the specific step from the reinstallation work package which replaced the items.
The system also contains item description, location, safety tag numbers, component description, reinstallation data, work package sign off date and the date a turnover memo was sent to the SURGE group to be used for milestone tracking.
The inspector discussed design changes with cognizant VY engineers to determine whether applicable plant drawings are being updated to the new system configuration.
The licensee showed the inspector updated system drawings, the vehicle by which outstanding system drawings will be up-dated, and the sy., tem by which MK as built drawings of interface piping /
components, will be incorporated into the licensee's document control system.
The responsible engineer from YNSD was knowledgeable of his duties and had a clear understanding of drawing control procedures.
The inspector toured the drywell to observe general restoration activi-ties and to verify that selected piping systems and electrical reconnec-tions conformed to as-built drawings.
In addition, selected snubbers and pipe supports associated with the RHR and recirculation system were inspected for proper installation.
No unacceptable conditions were identified.
3.4 Hangers Reinstallation Control The inspector reviewed the licensee's program for control of the instal-lation of hangers, and modifications of seismic piping supports.
The inspector noted that the review process involves three independent review l
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steps, with final approval by the Engineering Support Division of the plant staff.
Initial review / inspection of hanger installation is con-ducted by both a QC inspector and a draftsman to verify installation in accordance with the Mercury field installation drawings.
Following that review process, a separate QC review is, conducted to verify that instal-lation conform to design criteria.
Fir;al QA review of each completed package is the last step in the process.
The inspector reviewed the overall hanger installation control process and noted that it is effective in identifying and resolving problems.
Initial QC/ Draftsman field review identified five minor discrepancies between the drawings and actual field installation.
The inspector re-viewed the licensee's disposition of these discrepancies, and was satis-fled with the licensee's action.
The second step review process also identified three discrepancies between the field installation drawing and the design specifications.
These were the result of a drafting error.
The licensee's actions were prompt and effective in resolving this situ-ation.
The licensee put the three hangers in conformance by additional welding, and instituted an engineering review of the effects on system operability.
PORC review of the Non-Conformance Report related to these three discrepancies and analysis of the root cause of this problem was considered to be extensive and thorough.
3.5 Conclusion Based upon the areas reviewed, the team concluded that system restoration activities are progressing satisfactorily.
The licensee's approach to startup accomplishments is conservative and well controlled.
Licensee corrective action regarding identified problems is thorough and effective.
4.0 Quality Activities The scope of inspection effort in this area included an overview of Quality Assurance (QA) and Quality Control (QC) involvement in Vermont Yankee's opera-tional activities to access their overall effectiveress and their readiness for restart.
Specifically, the inspector reviend ;l) QA surveillance and audits; (2) design control; (3) maintenance activities; and (4) management involvement in assuring quality.
4.1 QA Surveillance and Audits The licensee has both onsite and corporate Quality Assurance representa-tion.
The onsite quality assurance group, Operation Quality Group (0QG),
is permanently staffed with one manager, one QA lead engineer, and four QA assistant engineers. As the need occurs, i.e., outages, etc., addi-tional contract personnel are hired or individuals temporarily trans-ferred from the corparate group to assist with the additional workload.
The 0QG Supervisor reports to the Director of QA in Framingham, but has a direct line of commurication with the plant manage.
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Three levels of control are in place at VY to ensure the proper execution of quality related activities.
These levels of control include: (1) in-dependent inspections, (2) surveillances, and (3) audits.
Independent inspections are accomplished through the peer inspection program.
Sur-veillances of daily activities are performed by the 0QG, including in-spections performed in accordance with the peer inspection program.
Audits, performed by the corporate audit group, are comprehensive evalu-ations used to verify that quality-related programs have been established and are being implemented effectively.
OQG coverage of both routine and nonroutine plant activities is accomp-lished through " scheduled," or " random / informal" surveillances.
The in-spector reviewed the OQG surveillance logs and determined that approxi-mately 400 surveillances related to the outage, both scheduled and random, have been performed to date.
In most instances, findings were resolved in a timely manner, and 0QG followup of identified items was noted.
The inspector noted during his review that surveillances cover a broad range of activities including: housekeeping / cleanliness controls, material receipt inspections, maintenance activities, design changes (EDCRs, PDCRs), training / certification, valve lineups, and Technical Specifica-tions compliance.
The inspector noted that the licensee had emphasized the material receipt area, as a result of previously identified concerns in this area.
0QG plans to continue this emphasis until satisfied that the corrective ac-
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tions which had been implemented for previous concerns are effective.
The peer inspection program was instituted informally in late 1985 as a means to perform independent inspection of quality related activities.
This involved review of work activities by knowledgeable craftsman not directly associated with the specific activities being reviewed.
The inspector reviewed Surveillance No.85-112 " Surveillance of Implementa-tion of Interim QC Program" which was an initial evaluation of the peer inspection program.
This surveillance was performed in October 1985, and documented over 20 items of concern with the peer inspection process in the areas of Maintenance, Operations, I&C, Reactor and Computer Engi-
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neering, and Chemistry & Health Physics.
In January 1986, the licensee formalized the peer inspection program through issuance of AP 6025 " Quality Control / Independent Inspection."
The 0QG performed another surveillance of this area during April 1986.
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This surveillance, No.86-101, " Surveillance of AP 6025 Implementation,"
noted that previously identified items of concern were corrected with the exception of those in the Chemistry and Health Physics area.
Prob-lems in Chemistry and Health Physics attributable to misinterpretations of AP 6025, which have been resolved and corrective actions initiated.
As noted in a previous section of this report, the licensee established a Startup/ Restoration Group Effort (SURGE) to verify plant restoration by specifying adequate preoperational and startup activities. The in-
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spector noted that 0QG had included SURGE related activities in their surveillance program including assigning areas of responsibility to specific 0QG engineers.
In addition to specifying areas of planned surveillances important to restart, the inspector also reviewed a memorandum specifying 0QG re-sponsibilities throughout the outage.
The areas of responsibilities included various maintenance requests, design changes, temporary lifted leads and jumpers, switching and tagging, procedures and T.S. adherence, leak rate testing, etc.
The inspector determined, based on his review, that QA is actively in-
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volved in assuring that outage activities are completed satisfactorily.
However, during this review the inspector observed that there was not a formalized program specifying 0QG manager review and control of 0QG
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activities.
Specifics would include his review of completed surveillance activities and approval reports / correspondences that are distributed to I
plant management, and department level supervision.
This observation i
is made in light of the past deficiency in communication between QA and l
plant management.
l 4.2 Design Control l
The inspector examined the licensee's programs for design and design changes to determine if activities were conducted in accordance with the
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appropriate specifications, drawings, and approved procedures.
The pro-i gram was also reviewed to assess the adequacy of procedural controls i
established for the interfaces among departments participating in the development of design and engineering criteria, independent technical review, technical and administrative approval, and the operational safety
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review of the change.
The inspector reviewed QA's involvemen'. with the following Plant / Engineering Design Change Requests (PDCR/EDCR) that were completed this outage, as documented via surveillance checklists:
EDCR 84-416, 345 KV Breaker 81-1T Replacement - 0QG-VY-85-131
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EDCR 85-402, Appendix "R" Fuse Stops and Conduit Wrap - 0QG-VY-86-56
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ODCR 83-06, HPCI Automatic Suction Transfer Removal - 0QG-VY-85-171
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The inspector also reviewed Audit Report No. VY-85-07 which was an audit of Design and Design Change controls.
This audit included a review of selected PDCRs, EDCRs, and Installation and Test procedures.
No unac-ceptable conditions were identified.
For PDCR 83-06, HPCI Automatic Suction Transfer Removal, the inspector reviewed and discussed the PDCR with appropriate personnel.
The PDCR involved the removal of three associated relays in the HPCI logic system.
The removal of these three relays would eliminate the automatic transfer of the HPCI suction from the condensate storage tank (CST) to the torus
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on a high torus level.
This change was instituted to provide HPCI pump
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The design function for automatic transfer from the CST to the torus on low CST level would remain.
The inspector reviewed the associated control wiring diagrams (CWD) and physically verified that the appropriate relays or associated wiring had been removed.
One relay (23A-K25) was left as an installed spare.
No unacceptable conditions were identified.
4.3 Maintenance Activities The 0QG receives copies of all maintenance requests (MRs) and is being notified prior to the start of any safety-related work.
0QG reviews de-sign change documentation and installation and test procedures and de-cides whether to witness inspections or tests.
0QG involvement for work done recently on the safety-related GE HFA relays was excellent. Core replacement of these relays resulted from NRC Bulletin 84-02, and subse-
quent GE Service Information Letters (SIls).
The inspector reviewed ten 0QG surveillances covering maintenance of these associated relays.
Recently, a problem has been identified regarding the correct contact configuration following completed maintenance on relay 23A-K22.
As a result, I&C is performing a reinspection of all relays worked on during the outage to verify proper contact configuration.
All relay contact configurations, as installed, are being verified against CP 5304 data sheets and associated CWDs.
The resident inspector is continuing to follow licensee actions in this area.
The inspector had no further questions.
4.4 Management Involvement in Assuring Quality VY management, during the past year, has focused significant effort in assessing and determining ways of improving performance.
Actions taken have included, 1) an overall assessment of the effectiveness of the Quality Assurance Program; 2) the establishment of a Quality Control Task Force chartered to evaluate the appropriateness of the " peer inspection
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program"; 3) the formation of the Startup/ Restoration Group Effort, as
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previously discussed in this report; and 4) the establishment of the
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Project Task Force that focused on assuring a quality product during the
replacement of the recirculation piping.
The actual conduct of these evaluations and the establishment of the SURGE and Project Task Force indicates that licensee management is committed to an aggressive program of following quality activities.
The licensee has acted on most recom-mendations resulting from QA/QC assessments noted above.
Remaining is-sues requiring resolution are currently under licensee evaluation.
l Emphasis has been placed on strengthening the communication between plant l
personnel (including plant management) and the QA organization.
This is significant, because past problems at Vermont Yankee have been attri-buted to a lack communication, thus reducing the overall usefulness/ef-fectiveness of QA as a management tool.
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4.5 Conclusion The quality activities associated with the outage were effective in as-suring proper restoration of safety systems to support resumption of power operation.
The comprehensive and aggressive action directed by licensee management to correct previously known weaknesses in the QA/QC area demonstrates a commitment to improve overall performance and is considered a strength.
r 5.0 Operator Readiness for Restart The inspector reviewed licensee training programs to ensure operators were prepared for restart and operation after eight months of outage activity.
The inspector reviewed requalification program records, reviewed training
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program Instructor Guides, attended classroom training sessions, attended simulator training sessions, and interviewed licensed personnel.
This review focused on three specific areas: (1) operator knowledge of system design changes and modifications; (2) maintenance of operational skills; and (3) operator knowledge of, and familiarity with Emergency Operating Procedures (E0P).
These areas are discussed in the sections below.
5.1 Maintenance of Operational Skills The inspector reviewed the licensee's program to ensure operators main-tained their operational skills, and were cognizant of TS and procedural changes that have cccurred since the beginning of the outage.
The in-
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spector reviewed Licensed Operator Requalification Lesson Plan " Single
Loop Ops / Stability Monitoring." The inspector also attended the re-
qualification program training class on TS and procedural changes.
The inspector reviewed operator participation in the requalification program i
since the outage began, reviewed the lesson plans from that period for adequacy, and attended a portion of simulator training for plant restart.
No unacceptable conditions were identified.
The inspector noted that requalification attendance during the outage was complete, and that the program presented an adequate range of subjects.
The classroom lecture on TS and procedural changes was good, with indepth instruction on the basis for these changes and the effect on plant operation.
5.2 System Design Changes and Modifications The inspector reviewed Licensed Operator Requalification Lesson Plan,
"1985/86 Outage Modifications," and Licensed Operator Requalification Lesson Plan "RETS-Radioactive Effluents Tech Specs." The inspector also attended the requalification program classroom session on modifications, and discussed modification training with the Supervisor of Licensed Operator Training and the Requalification Program Lead Instructor.
The modification and design change training given to licensed operators is considered lacking in both depth and scope.
The inspector noted that 11 modifications were chosen for training.
The inspector discussed the
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j process by which these modifications were chosen with the Supervisor of-i Licensed Operator Training and the Requalification lead instructor.
The
inspector noted that no formal program exists for the review of modifi-
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cations to determine whether they should be chosen for training.
No
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formal criteria or guidelines exist for selection, and no formal review
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mechanism including plant operations review exists to validate the selections that are made.
Discussions with the Training Supervisor in-dicated that he had criteria in his own mind to select modifications, but these were not documented.
The review of the lesson plans on modifications, and attendance at the
modification lecture indicated that the licensee is not presenting in-l formation to licensed personnel at a level of knowledge which would be
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expected for licensed operators. -The inspector noted that 11 modifica-l tions were presented in class in a period of one and one-half hours.
Of that time, 20 minutes was spent on intergranular stress corrosion cracking, leaving approximately one hour and ten minutes to cover eleven modifications. The inspector noted an absence of indepth discussion of system interrelations, procedural impact, and operational changes.
The
inspector also noted that it was evident that the training department
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had not performed an indepth preparation, including plant tours, to de-velop the modification lesson plan or lecture.
Based on the lack of depth and scope of training and the lack of a formal program to ensure that all required training on modifications is identi-fied, the NRC considers this area a weakness in the licensed operator
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training program.
The inspectors held discussions with senior licensee management-regarding i
this weakness and the licensee committed to review all modifications and I
conduct remedial training with all operators prior to reactor startup.
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5.3 Emergency Operating Procedures (EOP)
The inspector reviewed the licensee's program to ensure that licensed
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operators are thoroughly familiar with the new Emergency Operating Pro-cedures.
Details on the history of training on these E0Ps may be found j
in NRC Inspection Renan1s 50-271/85-10, 85-18, and 85-36.
The inspector interviewed personnal f) determine their level of familiarity with and their comfort fo !> e,x ! of, the E0Ps.
These interviews indicate that licensed perston 4 in.grneral are ready to operate the plant with the E0Ps, but that a desire for more plant specific simulator training on
the E0Ps exists.
y The inspector reviewed the licensee's plans for using the site simulator
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to train the-licensed operators on EOPs.
The licensee had conducted-t
formal simulator training on E0P 3105, Secondary Containment Control, il but had not conducted formal training on any.of the.other five E0Ps.
The licensee had planned to conduct training on these E0P's in January 1986.
However, due to delays _in simulator installation this was not
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Site simulator training was designed to supplement prior classroom and simulator training on the Dresden simulator conducted by
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General Electric in the Fall of 1985.
The licensee's plan was to conduct plant specific simulator training on the other five E0P's throughout the remainder of the 1986 requalification cycle, a period of about nine months.
In light of the inspector's discussions with licensed personnel, wherein a desire for more simulator training was expressed, the inspector ques-tioned licensee management regarding the possibility of conducting the same form of E0P training prior to startup as well as completing simula-tor training earlier in the requalification cycle.
On June 12, 1986, senior corporate management met with Region I to discuss this issue.
At this meeting, utility management agreed that a walkdown of the re-maining E0P's would be conducted by either the Plant Manager or the Operations Superintendent for each of the six operating shifts.
In ad-dition, site specific simulator E0P training would be conducted for each operating shift during the next complete training cycle, which will be completed in the first week of August 1986.
The additional training on the Vermont Yankee simulator proposed by licensee management, when com-pleted, should reinforce the familiarization with the E0P's.
5.4 Summary The licensee has committed to correct, prior to restart, deficiencies identified during the inspection regarding modification training end refamiliarization with E0P's.
The licensee's proposed supplemental training is acceptable and will provide the necessary level of licensed operator readiness prior to restart.
Other training areas examined dur-ing the inspection were found to properly support resumption of plant operation.
6.0 Preservice NDE Activities The inspectors reviewed selected Modification and Maintenance activities to assess the licensee's welding program including NDE and preservice baseline examinations.
Specific areas reviewed included: (1) recirculation piping replacement, including an allegation regarding pipe fitup problems; (2) re-circulation piping replacement preservice inspection (PSI) data review; (3) condensate storage tank (CST); and (4) personnel qualification /certifica-tion records of receipt inspectors.
6.1 Recirculation Piping Replacement The purpose of the recirc piping replacement was to prevent continuation of intergranular stress corrosion cracking (IGSCC) of the stainless steel pipe welds.
The licensee provided for additional protection from this corrosion mechanism by performing Induction Heating Stress Improvement (IHSI).
Seventy (70) welds in the recirculation, and residual heat re-
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moval systems were treated by IHSI.
Following the initial equipment set up, the IHSI was performed between April 24 and May 8, 1986.
The appli-cation of IHSI in addition to selecting the Type 316 NG stainless steel is considered to be a significant strength in the pipe replacement pro-ject.
The licensee identified the contractor for replacement early providing the contractor time tp initiate measurement in the drywell during the preceding refuel outage, established a dedicated licensee project team to oversee the project and provided for technical support in this organi-zation for resolution of project problems.
The overall project planning and organization are considered as strengths identified during this and related project inspections and meetings.
The inspector reviewed work package 1222/0 for installation of recircu-lation suction and discharge piping, Loop "B" to determine that work was performed in accordance with applicable requirements.
The inspector re-viewed selected weld cards, Design Change Notices, Non-Conformance Re-ports, Open Item Reports, Inspection Reports, Liquid Penetrant Inspection Reports, Visual Weld Examination Reports, ALARA, and Radiographic Inspec-tion reports.
No discrepancies were noted.
During review of work packages, the inspector noted the identification symbols of a sample of welders.
The qualification test records of Morrison-Knudsen Company were reviewed for comparison to the requirements of the Field Welding Procedure (FWP 2.1) for welder qualification and the ASME Code Section IX.
The welder qualification records were cross checked against Revision 29 of the list of qualified welders for the recirculation pipe welding.
No deficiencies were noted.
The inspector reviewed the following radiographs and reports of radio-graphic examination of recirculation system pipe welding for comparison to the requirements of the Radiographic Examination Procedure FQP 9.4 and the ASME Code Sections III, V and XI.
AS-3 B
N20-SE B
BS-1 B
N20-1 A
N2J-SE B
BS-5 A
N2H-SE B
BD-11 B
N2-D2 B
BD-9 All radiographs and associated reports were in conformance with existing requirements.
The inspector reviewed the following work packages (instructions and documentation of work) and corresponding weld data sheets which pertained to N2 nozzle repair.
Repairs, where required, were noted to be documented.
All documentation examined conformed to existing requirements.
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Work Package Scope 1423 Install N2J 1413 Machine N2J Safe End/ Nozzle 1428 Install N2D Safe End 1422 Install N2H Safe End Work package review indicated extensive use of intermediate radiography at the level of the first 3/8" of weld in the root of recirculation pipe welds.
While this procedure did result in an increase in repair welds in the root area due to the increased sensitivity in examination of this reduced section thickness, it permitted identification of root weld problem indications so as to provide for repairs before the welding was complete.
The persistence of continuing intermediate radiography and clearing of root weld indications prior to welding th3 joint completely is considered a strength of the recirculation weld project.
Besides reducing schedule time, this, in permitting root repairs to be made prior to completion of the whole weld, is expected to have produced a more uniform stress field in the completed wald, therefore contributing to a reduction potential for IGSCC.
6.2 Followup of Allegation Regarding Ricirculation Piping Replacement The NRC received an allegation which expressed concerns that recircula-tion piping provided by a Japanese supplier was incompatible with asso-ciated U.S. made piping or components.
The allegation was expressed in generalities and contended that fitup problems existed during installa-tion.
The inspector reviewed the potential safety significance of this allegation based on the limited information.tvailable.
The inspector reviewed QC receiving inspection reports, pipe assembly work packages, weld data cards, applicable procedures and Non-Conformance Reports to establish if ASME Code and procedural requirements were met during recirculation pipe system fitup for welding.
The objective was to examine controls and documentation of weld joint fitups and determine if there were fitup problems.
In general, pipe to pipe joint edges were received from Hitachi in the as-machined condition while pipe ends for welding to pumps or valves were cut square with extra material for machining to exact length to match field conditions.
Receipt inspection included verification of the weld joint preparation land, bevel, radius and counterbore dimensions of weld procedure M-8-8-A, Figures 4 or 5 and applicable drawings including W-005-D and 10P122-863.
The finding of a deviation from the requirement of the ordering specification or drawing was documented by the receiving inspector on a Material Disposition Report (MDR).
The MDR was then sub-mitted for engineering review with corrective action if required on a Non-Conformance Report (NCR).
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The attribute of weld joint fitup is item number one on each weld data card for each individual weld joint and is a quality control inspection hold point for every pressure retaining pipe weld.
The inspector re-viewed eleven NCRs issued up to 1/17/86 on recirculation system pipe joint dimensional problems and noted minor variations, typically less than 0.010" out of drawing tolerances.
The inspector was unable to substantiate the presence of a problem with supplied piping joint preparations that would cause a problem in matching pipe plant components.
During this review the inspector noted that the receipt inspection function and involvement of engineering in the evalu-ation and disposition of identified problems was thorough and competent.
Additionally, the inspector noted that all weld fitups were required to be inspected by QC.
Based on the inspector's review of the information provided, this allegation was found to be unsubstantiated and is there-fore considered closed.
6.3 Recirculation Piping Replacement Preservice Inspection (PSI) Data Review The inspector reviewed data representing shop welds and field welds in the recirculation system and RHR piping.
The review was done to ascer-tain that ASME Code requirements, regulatory requirements and licensee commitments were met, and that properly qualified and certified NDE per-sonnel performed the examinations.
The inspector found that the welds were examined to the greatest extent possible in accordance with ASME Section XI requirements.
Examination limitations are identified on the data sheets for specific welds.
The ultrasonic examinations were done by qualified personnel.
Examinations were done prior to IHSI treatment, and a sample was re-examined subsequent to IHSI treatment.
If significant changes were noted in the acoustic properties after IHSI of a particular weld configuration, all of that configuration was re examined.
All welds were examined with the P-Scan technique and, in addition, manual scanning was done on selected welds.
All P-Scan data were analyzed by an EPRI requalified Level III individual, although the licensee was not required to use re-qualified personnel for new piping examinations.
The PSI data was found to be extremely well organized and complete. A book of data was provided for each weld and included a summary sheet listing all the examinations to which the weld was subjected and the results.
No violations were identified.
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6.4 Condensate Storage Tank (CST) Repair The Condensate Storage Tank at Vermont Yankee was designed, fabricated and erected to the requirements of USAS B96.1 for Welded Aluminum-Alloy Field Erected Storage Tanks and to Ebasco Specification No. 5920-58.
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The licensee identified a leak in the tank caused by two 3/16 inch holes in the bottom.
Ultrasonic thickness measuring techniques were used to determine the condition of bottom plates in the vicinity of the holes and in other locations where corrosion was anticipated due to an earlier tank overflow.
The thickness measurements were made by the licensee's ISI vendor personnel who were certified as UT Level II and Level III individuals.
All areas which measured less then 0.250 inches thick were repaired by welding aluminum plate over the degraded areas of the original bottom plate. The new plate was fabricated of aluminum 5454 alloy, and was the same as the original design material.
The licensee is currently investigating the cause of the corrosion, and is performing tests to determine the corrosion rate.
The present repair is considered by the licensee to be an interim fix with permanent repairs to be scheduled based on the results of the continuing evaluation.
The resident inspector will follow the licensee's resolution of this issue (271/86-13-01).
6.5 Personnel Qualification / Certification Records of Receipt Inspectors The inspector reviewed perponnel records of selected individuals who perform receipt inspections at Vermont Yankee.
The review was done to ascertain that the requirements of ANSI N45.2.6, 1978, the governing document, were met.
A statement from the licensee's contractor stated that the individuals were certified as Level II visual inspectors.
The onsite records in-cluded experience and training for each individual, but visual acuity examination records were not included.
The licensee contacted its con-tractor and was advised that the records regarding eye examinations were held by the contractor.
However, to avoid delays in obtaining these records, the licensee, on 6/6/86, performed visual acuity examinations of the involved personnel.
Additional licensee attention to completeness of contractor provided cerifications is recommended.
6.6 Conclusion The organization and thoroughness of the pipe replacement aspects of the outage showed evidence of extensive planning and direction by the licen-see to obtain the high degree of cooperation of the two vendor groups involved with the recirculation piping replacement activities.
Licensee performance in the area of pipe installation and associated welding, NDE and quality activities is a notable strength.
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7.0 Outage Health Physics The licensee's health physics (HP) program for control of radioactive material, personnel exposures, and work in radiological areas was reviewed.
Specific elements covered in this review included: (1) management controls and staffing; (2) implementation of the Radiation Protection Program, including surveys and radiation work permits; (3) external and internal exposure controls and respiratory protection; and (4) outage ALARA Program.
7.1 Management Controls and Staffing The licensee's management controls and staffing to accommodate the re-circulation piping replacement project and other outage related activi-ties was reviewed by direct observation of ongoing work activities; and discussion with radiation workers, contractor and licensee HP technicians, and licensee and contractor supervisors.
The licensee exercised aggressive control over work activities in the drywell during the recirculation piping replacement project.
Control point managers were established, and given authority to stop work if the control of work activities was being compromised with respect to numbers of people in the drywell and numbers of jobs.
Adequate numbers of HP staff were available to coordinate job activities, and oversee work in progress.
Additionally, there appeared to be generally effective commu-nication between Health Physics and the various plant and contractor groups.
7.2 Implementation of the Radiation Protection Program The licensee's program for radiation surveillance of plant areas, and control of job activities was reviewed with respect to criteria contained in the appropriate regulations, the licensee's technical specifications, and the licensee's commitment to the NRC in letter FVY 85-52, dated May 31, 1985.
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The licensee's performance was determined by:
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a review of 2C radiation work permits (RWPs), the supporting surveys and sign-in sheets; observations during tours of the drywell and general plant areas;
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review of control point log books; and i
discussions with various licensee and contractor personnel.
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There were no violations or deviations identified during this review.
Due to the excellent operating history of this plant, and vigilant house-keeping efforts, dose rates and contamination levels were reduced, there-by minimizing exposure to workers.
Also ALARA coordinators and various i
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other outage personnel supplemented the routine survey program with de-tailed surveys of recirculation piping valves and pumps to support the radiological controls established by the licensee.
However, the inspec-tor noted the following with respect to radiation wurk permits (RWP):
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RWPs were written at the Health Physics checkpoint office without the supporting surveys readily accessible.
The inspector found one instance in which the improper survey information was included on one RWP.
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RWPs were not posted with the supporting surveys for workers to re-view prior to entering the work area.
The licensee depended upon access control point technicians to brief workers prior to entry, and continuous and/or roving HP technicians to monitor work activi-ties in progress.
The inspector discussed these observations with the licensee.
The lic-ensee stated that these observations were also made by the ALARA staff, and that the RWP program would be reviewed and revised when the outage was over (271/86-13-02).
7.3 External and Internal Exposure Controls The licensee's program for monitoring and evaluating inter.1al and exter-nal exposure was reviewed with respect to the pertinent regulatory re-quirements and the licensee's technical specifications.
The licensee's performance in these areas was determined from:
review of exposure records for selected radiation workers;
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review of control point logs and the whole body counting log;
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review of the licensee's procedures for personnel monitoring, and respiratory protection;
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observations of air sampling and air sampling techniques during drywell tours; and
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discussions with licensee and contractor personnel.
There were no violations or deviations identified during this review.
The inspector observed that all personnel wore dosimetry as required by the licensee's procedures.
The inspector also noted that the licensee adequately evaluated drywell conditions for airborne activity by taking timely air samples.
The effectiveness of the licensee's respiratory protection program was verified by whole body counting personnel prior to leaving the site and whenever a suspected uptake occurred (e.g., per-sonnel contamination).
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The licensee's respiratory protection program contained the essential elements required in 10 CFR 20.103 (C)(2).
However, the inspector noted that the licensee's program for respiratory protection did not conform with current standard industry practices.
The following weaknesses in this program were noted:
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The licensee modified the fit test booth by machining a new stain-less steel air-jet generator to replace the original brass generator.
However, the licensee did not verify that the new generator's per-formance was consistent with the original manufacturer's equipment.
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The licensee reused the HEPA filters for the full-face particulate masks.
However, the licensee did not retest the filters for dust loading or for efficiency prior to use.
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The licensee stored masks with the straps pulled over the facepiece, potentially leading to deformation of the facepiece sealing surface and scratching of the respirator visor.
The inspector discussed these concerns with the licensee.
The licensee stated that they would review their respiratory protection program for conformance with current acceptable industry practices.
7.4 Outage ALARA Program The licensee's "As Low As Reasonably Achievable" program for the recir-culation piping replacement project (RPRP) was reviewed by discussions with the outage ALARA staff, Outage Project Coordinators, and a review of final work packages.
The ALARA staff, established for the RPRP, as-sembled detailed work packages for various outage activities which in-cluded pre-job planning, on going work modifications, and post-job re-views. The packages will provide the licensee with valuable historical information for future work as well as dose saving and dose reduction techniques.
The inspector compared the final total doses of selected work packages with published doses for comparable work (NUREG/CR-4254).
In all pack-ages reviewed, the licensee's final total exposures compared with the minimum to average exposures published in the study.
As of May 31, 1986, the licensee had expended 2175 man-rem, with 1720 man-rem of this total associated with the recirculation system piping replacements.
The licensee's cap for the outage was 2300 man-rem with 1800 man-rem projected for the recirculation system piping replacement.
7. 5 Conclusion The inspector conducted that overall management of radiological controls activities during the outage was good. Work activities were properly monitoring and technicians were strongly supported by Plant Management.
However, one area of the respiratory protection program was considered below industry standards and the licensee will address this problem.
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8.0 Plant Condition / Facility Tours Periodically during the inspection the team toured the facility to determine the state of readiness for restart and radiological and general housekeeping conditions.
The inspectors toured all levels of the reactor building includ-ing the torus room area, turbine building and radioactive waste facilities.
Additionally, four entries were made into the drywell.
In general, conditions were good considering that the facility is removing equipment and material after a long outage.
The drywell is generally clear of interference.
There were some minor housekeeping deficiencies that were identified to plant staff and promptly corrected.
The team concluded that upon removal of outage re-lated equipment and material, there were no conditions that would prevent reactor startup.
9.0 Action on Previous Findings (Closed) IFI (271/86-01-05) N2D and NlA radiograph indications prior to safe end replacement.
Part of the safe end replacement sequence is to radio-graphically inspect (RT) the nozzle and safe end weld prior to safe end re-moval to assure that the area to be welded is sound metal.
During this RT of N2D and NlA, indications were identified in the safe end of N2D (two axial cracks) and in safe end weld of NlA (lack of fusion).
The N2D axial cracks were not unexpected as the basic purpose of the pipe re-placement was to prevent continuation of IGSCC which includes axial cracking.
The construction radiograph for NlA was done with Cobalt 60 isotope and ASTM Type II (AA) film as compared to the use of Iridium 192 with ASTM Type 1 film during the replacement sequence.
This film-source combination is more sensi-tive than Co 60 with Type II film as demonstrated by showing a minor area of lack of fusion on the NlA.
The licensee evaluation of the N2D and NlA defects determined them to not be reportable.
The indications were removed and not present on radiographs of the completed N2D and NlA welds. This item is closed.
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(Closed) Unresolved Item (271/86-08-03) Structural overlay of core spray noz-zles (NSA, NSB).
Ultrasonic examination of the NSA and NSB core spray nozzles in the safe end to nozzle weld area located indications indicative of inter-granular stress corrosion cracking (IGSCC).
A letter dated May 5, 1986 from W. Murphy (VY) to D. Muller (NRC) provides the background of this problem and describe the repair method.
This repair design includes a temper bead tech-nique weld deposit on the P3 nozzle material per the ASME Code Case N432 fol-lowed by a weld overlay of 0.50" minimum thickness.
The inspector reviewed the May 5, 1986 submittal and relevant repair contrulling documentation in-cluding work package SPN 70430-700, Job Number 70430.
Weld records, welding in progress and the weld surface of the overlay were examined.
The inspector concluded that the weld overlay including temper bead welding were being ac-complished within the repair program scope presented in the referenced May 5, 1986 letter and applicable portions of the ASME Code.
Documentation of the work was noted to be current with the work status.
QA and engineering were involved in pre-work activities and during the repair process.
This item is close.
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(Closed) Unresolved Its.m (271/86-08-02) Removal of a stainless steel pipe section from the low pressure side of RHR line.
The reactor side of the two j
RHR discharge lines and one RHR suction line are bounded by valves V10-18, l
V10-46A and V10-46B.
The low pressure side of V10-46B is shown on P&ID 191172 to be welded to a carbon steel RHR pipe section.
The P&ID 191172 also shows
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valves V10-46A and V10-18 to each be welded to a short stainless steel pipe
section which in turn is shown on the P&ID to be welded to a carbon steel RHR I
piping.
Field observation of V10-18 determined that it was welded to a carbon steel pipe material similar to that by V10-46B.
The inspector reviewed the field change modification documentation dated March / April 1971, noting the present installation of carbon steel pipe welded to the stainless steel valve a
V10-18 to agree with the 1971 field documentation.
The EDCR 85-1 provides for revision of the P&ID 191172 to show the 1971 field change.
The RHR piping to valve V10-46A was not field revised during original con-struction such that it was welded to a l'-6" long stainless steel pipe section that was shop welded (SW-56) to a l'-7" carbon steel pipe section.
During the 1986 outage, these two short sections of piping including the stainless steel section were removed and replaced with a single carbon steel pipe sec-tion. The inspector examined this new pipe section in place and reviewed the work package 70429 providing controls and documentation during installation.
Weld radiographs for FW#1 and FW#2 and portions of the installation and test procedure EDCR 85-01 (ECN#8) were reviewed.
The inspector concluded that the low pressure side of the RHR lines past valves V10-46B, V10-46A and V10-18
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are no longer stainless steel. Work was shown to be in accordance with ap-plicable ASME Code and specification requirements.
This item is closed.
(Closed) Unresolved Item (85-18-03), E0P 3104 Torus Level Instrumentation
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Modification.
The inspector verified that the licensee, under EDCR 84-429,
has begun installation of this instrument as part of overall Reg Guide 1.97 Instrumentation Upgrades.
The completion of this modification will be tracked
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as part of the resident routine inspection of outage activities.
This item
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is closed.
(Closed) Unresolved Item (85-20-02), Environment Qualification of LPRM Cables.
The licensee, under EDCR 84-427, is replacing LPRM cabling in the reactor building with Rockbestos RSS-6-104 coaxial cable.
This cable is qualified to a level which exceeds the expected reactor building post-HELB (High Energy
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Line Break) environment.
In addition, the licensee is replacing the drywell penetration connectors with EQ qualified Litton-Veam connectors, and existing
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drywell cabling with Rockbestos RSS-6-104.
Under vessel connectors will be
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replaced with EQ qualified QLN quick release connectors.
Interim SMA/QLN
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pigtails will be used until all of the LPRMs are replaced during subsequent outages.
Until that time, the existing SMA connector to the LPRM itself, will be qualified with the application of Raychem shrink.
Completion of this modification will be tracked as part of the routine resident inspection of outage activities.
This item is closed.
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i (Closed) Unresolved Item (85-30-09), Feedwater Leak Rate Test Failure Analysis.
The licensee's evaluation of leak rate test failures on Feedwater Check Valve 96A was reviewed by the inspector.
The licensee concluded that the Appendix J LLRT failures of the 96A valve were due to the disc not being able to free swing about the hinge due to improper reassembly at the time of installation.
This has been resolved by machining.
The inspector noted that the. licensee's review was thorough and technically sound.
The inspector also noted that after the corrective actions by the i
licensee, the 96A valve passed its LLRT.
This item is closed.
(Closed) Inspector Followup Item (86-01-12), Revision to OP 3140.
Licensee action to revise alarm response procedures per OP 3140 for a " low grid voltage without an accident signal." The inspector verified that the procedure was i
revised and completed on May 28, 1986, and had no further questions.
This item is closed.
i (Closed) Inspector Followup Item (85-39-01), Calibrate area radiation monitor installed in the TIP room.
Calibration of the Eberline RMS II area radiation monitors, with readouts located outside the TIP room and in the control room were performed on May 6, 1986.
Additionally, Procedure R.P. 4522 was written to provide detailed instructions and acceptance criteria for calibration of this system.
This item is closed.
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(Closed) Inspector Followup Item (85-39-03), Ensure that traversing in-core
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probes (TIPS) are stopped within shielding when withdrawn from the core.
The newly designed TIP drive mechanism and indexing system was installed which
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employs a transducer coupled to the drive mechanism.
The new system enables i
the licensee to place the probes within the shielding by direct measurement of cable length.
This item is closed.
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(Closed) Violation (85-36-02), Failure to complete calibration of the refueling floor radiation monitors in accordance with OP 4511.
The licensee's correc-tive actions, as stated in a letter dated February 5, 1986, were reviewed and l
verified.
The inspector determined that the corrective actioas specified in
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the licen:ee's letter were sufficient to prevent recurrence.
This item is
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closed.
(Closed) Unresolved (86-07-01), Failure to adhere to AP 0502 for specific job scope radiation work permits (RWPs).
The inspector verified the licensee's corrective actions, as stated in inspection report number 86-07.
The licen-see's corrective actions appeared sufficient to prevent recurrence of this
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j incident.
This item is closed.
(Closed) Unresolved Item (50-271/86-01-01), Valves CST 11, 11A, 11B not leak rate tested.
The inspector reviewed the LER submitted as a result of this
event and found the licensee's evaluation and corrective action satisfactory.
The licensee has completed a verification program of all penetrations identi-
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l fied as spares in the Vermont Yankee Containment Leak Rate Testing Program
and no other discrepancies were found.
Vermont Yankee completed a design
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- change to remove these valves from the system.
The containment testing pro-gram will be updated to reflect this change and the penetration will be tested prior to startup. This item is closed.
(Closed) Unresolved Item (50-271/86-01-09), Crossed pressure switch sensing lines.
The inspector reviewed maintenance request (MR) 86-0081 which cor-rected the crossed sensing lines on PS-2-128A and 1288.
This MR replaced in-strument tubing from the pressure switches to the penetration valves and en-sured that the retubed lines were connected to the proper instrument by leak testing the lines and fittings to 1150 psi.
In addition, a hand over hand check to ensure the new sensing lines were properly installed and tagged was conducted by licensee personnel.
This item is closed.
(Closed) Inspector Followup Item (50-271/85-35-01), Identification, Storage, and Control of Items for Reuse in Safety Related Work.
The inspector reviewed the licensee's methods for identification, control and storage of items for reuse in safety related work with cognizant engineering personnel.
To ensure segregation of scrap and reusable items, scrap material was removed from the reactor building and placed in appropriate containers for shipment off site.
At present, all material designated for reuse has been installed in the plant.
The inspector toured the reactor building with a licensee engineer and deter-mined that adequate controls exist for material now turned over from the con-tractor to the licensee for disposition.
This item is closed.
(Closed) Violation (84-18-01), Failure to Maintain System Valves in Proper Position.
The status of corrective action for this item was addressed in Inspection Report 84-26.
Tagging procedure AP 0140 was to be revised to strengthen caution tag controls to ensure that equipment restoration positions are consistent with plant status conditions when the caution tags are cleared.
A step in the procedure ensures that the control authority refers to the specific configuration in the normal operating procedure for the existing plant conditions when restoring equipment to service.
The inspector discussed this item with the Senior Operations Engineer and confirmed that the above changes had been completed (AP 0140, Revision 11, dated May 2, 1986).
This item is closed.
(Closed) Unresolved Item (85-40-06), Concrete Embedded Base Plate Not Properly Anchored to Concrete Column.
The base plate on pipe support MS-HD 22E, located on the HPCI discharge line, fell from the building column on which it was mounted when workers removed the support during modifications.
Licen-see evaluation techniques such as infrared scanning could not conclusively confirm that base plates were properly mounted.
Therefore, a decision was made to provide additional anchoring (by means of Hilti bolts) for 22 affected safety related supports. At the close of the inspection, modifications were in progress (EDCR 84-402, ECN #13) and nearly completed.
NRC inspectors ex-amined two modified supports and observed one modification in process to con-firm accomplishment in accordance with ECN #13 design drawings.
A discussion of the work was held with the craft supervisor in charge of modifications.
No problems were identified.
This item is closed.
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(Closed) Violation (271/85-22-01), Issuance of non-safety-related component for a safety-related application.
The licensee revised AP 80806 by adding additional instructions / checkoffs which should ensure the issuance of safety-related components for safety-related applications.
Stores personnel were also reinstructed to this effect.
The inspector reviewed the revised proce-dure and associated documentation to verify that adequate corrective action had been taken.
This item is closed.
(Closed) Inspector Followup Item (271/85-23-01), Licensee to conduct and com-plete a comprehensive management review of the QA program.
The licensee has recently completed an evaluation of the effectiveness ofthe QA program.
The inspector reviewed the results of this evaluation, which included a subsection
on QA-related procedure adequacy (IMPELL report).
Discussions were also held with various personnel as to any actions that are planned to be taken as a result of this evaluation.
This item is closed.
(Closed) Violation (271/85-25-01), Failure to identify test results that are outside the stated acceptance criteria.
AP 0310 was reviewed with department personnel and foreman.
Specific emphasis was placed on Steps A.13 and A.15.
Also Memorandum File #VYB 85/284 was issued, which emphasized the importance of one's signature when attesting to having performed a review.
The inspector reviewed the memorandum and attendance sheet which documented action taken by the licensee in this area.
This item is closed.
(Closed) Violation (271/85-25-02), Failure to implement corrective actions to preclude recurrence of deficiencies in the onsite QC peer inspection program.
Several corrective actions, with respect to the peer inspection program, were taken by the licensee.
These actions included: (1) correction of identified deficiencies with the peer inspection program; (2) the creation of a Quality Control Task Force to identify the adequacy of the peer inspection program or other alternatives; (3) development of an administrative procedure to pro-vide clear implementation guidance; and (4) conduct of surveillances, as deemed necessary of the peer inspection program.
The inspector reviewed AP 0625, the results of the QC Task Force study, and two surveillances,85-112
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and 86-101, which all dealt with corrective actions performed to correct in-adequacies with the peer inspection program.
Based upon the above results and the inspector's review, this item is closed.
(0 pen) Inspector Followup Item (85-40-09), Potential RHR Pump Problems.
The licensee has established an enhanced pump vibration monitoring program.
This program, started in May 1986, consists of taking sound vibration measurements at various locations on all RHR pumps once per month.
The licensee currently uses a consultant to evaluate this data.
Evaluation of the data taken during the first test showed a 13.5 Hz frequency line, which is considered an indi-cator of potential wearing problems, on RHR pumps A, B, and C.
The inspector discussed this indication with the licensee and the licensee's consultant.
The consultant stated that the amplitude of the vibration was very low and was not now indicative of deteriorating pump performance.
He stated that the licensee should continue to collect data monthly and that any changes in amplitude of the 13.5 Hz line be carefully evaluated.
This consultant also
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i stated that it would be useful to have data for varying pump flow tenditions.
The licensee is planning to perform the additional testing requested by the consultant during the next scheduled test.
Based on the results of the vibration testing completed to date and the lic-ensee's planned continued monitoring of pump performance, the NRC has no fur-ther questions regarding operability of the RHR pumps for reactor startup.
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However, the inspector will continue to closely follow the licensee's pump l
performance monitorir.g program.
10.0 Persons Contacted J. Weigand, President and Chief Executive Officer W. Murphy, Vice President and Manager of Operations J. Pelletier, Plant Manager
P. Donnelly, Maintenance Superintendent R. Wanczyk, Technical Services Superintendent D. Reid, Operations Superintendent R. Leach, Chemistry and HP Supervisor C. Johnson, Operations Supervisor
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R. Lopriore, Maintenance Supervisor r
T. Watson, I&C Supervisor
B. Buteau, Reactor and Computer Engineering Supervisor M. Matell, Engineering Support Supervisor R. Mossey, Construction Supervisor, Mechanical J. Massey, Construction Supervisor, Electrical
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W. Wittmer, Project Manager, Recirculation Pipe Replacement Task Force J. Gianfrancisco, Construction Supervisor, Recirculation Project
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J. Hoffman, Engineering Supervisor, YAEC i
l A. Small, QA Manager, YAEC A. Shepard, Director, QA, YAEC
11.0 Management Meeting
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During the inspection, licensee management was periodically informed of pre-liminary findings.
In addition, the findings were presented to senior licen-
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j see management at an exit meeting held on June 6, 1986.
No written material l
concerning inspection results was provided to the licensee during the inspec-
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tion, i
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