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Insp Repts 50-245/97-202,50-336/97-202 & 50-423/97-202 on 970529-0721.Violations Noted.Major Areas Inspected: Operations,Maint,Engineering & Plant Support,Including Emergency Preparedness Issues & Fire Protection Activities
	ML20216C812
Person / Time
Site:	Millstone
Issue date:	08/29/1997
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20216C700	List: IR 05000245/1997202; ML20216C695; ML20216C747;
References
	50-245-97-202, 50-336-97-202, 50-423-97-202, NUDOCS 9709090144
	Download: ML20216C812 (92)
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION SPECIAL PROJECTS OFFICE Docket Nos.: 50-245 50 336 50-423 Report Nos.: 97-202 97-202 97-202 License Nos.: DPR-21 DPR-65 NPF-4R Licensee: Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06385 Facility: Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at: Waterford, CT Dates: May 20,1997 - July 21,1997 Inspectors: T. A. Easlick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 A. L. Burritt, Resident inspector, Unit 1 R. J. Arrighi, Resident inspector, Unit 3 J. W. Andersen, Project Manager, Unit 3 R. S. Bhatia, Reactor Engineer J. E. Carrasco, Reactor Engineer D. A. Dempsey, Reactor Engineer J. T. Furia, Senior Radiation Specialist L. M. Harrison, Reactor Engineer J. H. Lusher, Health Physicist D. T. Moy, Reactor Engineer ,

L. L. Scholl, Reactor Engineer M. A. Biamonte, NRR R. Pelton, NRR M. Kotzalas, NRR J. B. O'Brien, NRR P. Bezier, NRC Contractor J. C. Higgins, NRC Contractor S. M. Wong, NRC Contractor Approved by: Jacque P. Durr, Chief Inspections, Special Projects Office, NRR

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9709090144 970829 PDR G

ADOCK 05000245 PDR

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TABLE OF CONTENTS

EXECUTIVE SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv {

l U1.1 Operations ..................................................1 U101 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 U 1.ll M aint enan ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 U1 M3 Maintenance Procedures and Documentation ................5 l U1 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . 6 l U 1.lli Enginee ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

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U1 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 U1 E3 Engineering Procedures and Documentation ................ 9 U2.1 Operations .................................................10

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U201 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 12 U 2. ll M ain t en a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3

i U2 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 13 U 2.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 U2 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 15

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U3.1 Operations .................................................22 U301 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

. U3 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . 24

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U3 08 Miscellaneous Operations issues (92700) . . . . . . . . . . . . . . . . . 26 i

U 3.li M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 9 U3 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 U3 M3 Maintenance Procedures and Documentation .............. 34

U3 M4 Maintenance Staff Knowledge and Performance ............41

U3 M8 Miscellaneous Maintenance issues . . . . . . . . ............. 43 U 3.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 7 U3 E2 Engineering Support of Facilities and Equipment ............ 47 U3 E3 Engineering Procedures and Documentation ............... 49 U3 E8 Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . 57

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IV Mant Suppod .................................................66

R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . 66 R5 Staff Training and Qualification in Radiological Protection and Chemistry Controls ... ............................69 i P4 Staff Knowledge and Performance in Emergency Preparedness . . 69 ii i

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P8 Miscellaneous Emergency Preparedness issues . . . . . . . . . . . . . 74, F1 Contial of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . 74 F4 Fire Protection Staff Knowledge and Performance . , . . . . . . . . . 76 F7 Quality Assurance in Fire Protection Activities . . . . . . . . . . . . . . 77 V. M anagement M eeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 8 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 8 iii

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EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/97 202; 336/97 202; 423/97-202 Operations At Unit 1, recent changes within the operations department require the shift managers to report to the assistant operations manager, a new reporting requirement and a change from the previous responsibility of the assistan Following a review of the concerns raised by the inspector, operations management has taken steps to ensure that the roles of the operations manager and the assistant operation manager are clearly defined, including the new reporting structur (U1.01.2)

During a review of the restoration process for the Unit 1 service water system, the operations staff was not initially using a new operation departmental instruction,1 -

i OPS-6.32 " Millstone Unit 1 System Readiness Review," which would have enhanced the restoration by providing a formal process for returning a system to an ,

operable or available status. AdditionaS an individual assigned as the overall '

management lead for the evolution did not function in that capacity. The reactor l _ operator assigned to control and monitor the restoration activities from the control room, did an excellent job coordinating the step-by-step activities with the field

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operators, and kept the unit supervisor informed of each step of the restoratio There was also good coordination between. operations, the test engineer, and the management test lead. The service water normal operating procedures did not contain appropriate guidance for determining normal system operating parameters following the system restoration. (U1.01.3) Overall, operator pedormance at Unit 2 was good in evaluating shutdown risk by maintaining awarenes's of plant cor.ditions and equipment availability, in particular, on July 14,1997, operators exhibited a good questioning attitude regarding the planned removal from service of the spent fuel pool area ventilation supply fa (U2.01.1)

e At Unit 2, the licensee initiated effort in removing 10 non-conservative technical specification clarifications from the technical requirements manual was goo (U2.01.2)

-e At Unit 2, the total backlog of 780 condition reports (CRs) that are greater than 120 days old indicates that timeliness for completing corrective actions continues to be a concern. The new management planned to demonstrate a higher standard by dispositioning newly generated CRs in a timely manner while establishing a plan for working off the CR backlog that existed when they arrived. However, the backlog of 200 CRs greater than 120 days old that were generated in 1997 indicates that the new management is also ineffective in addressing the corrective action timeliness issue which is considered a significant weakness. (U2.01.3)

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At Unit 2, although the licensee determined that there would be whient net positive suction head available to the reactor building closed cooling Wer (RBCCW)

pumps, the failure to evaluate and proceduralize the level band that operators should control RBCCW surge tank level was considered a weakness. (U2.03.1)

. Although the loss of spent fuel pool cooling at Unit 3 was not significant from a design basis or safety related viewpoint, it was significant not only with respect to -

the adequacy of current operational and configuration control but also management's expectation for operational standards. The former appears to have been addressed by the licensee's Event Review Team (ERT) report, while the latter was in the process of being assessed at the close of this inspection period. The NRC will continue to monitor the licensee's assessment of this event, its generic implications on the adequacy of other programs, and the implementation of effective corrective actions. (U3.01.1)

At Unit 3 the Nuclear Oversight organization appeared to be actively involved in quality assurance und assessment activities directed toward effective corrective actions for identified problem areas and program enhancements to improve future operations. The initiatives reviewed this period attest to a more active role by Nuclear Oversight in dealing with line performance. However, while the routine QA j < and oversight reports document cognizance of the areas which represent the most ,

significant challenges to improving performance, the ability of Nuclear Oversight to effect positive changes has not yet been fully demonstrated. (U3.07.1)

NRC review of several LERs established that while the licensee's operational activities were proper evolutions, literal compliance with the plant TS had not been j

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maintained. Based on the appropriate corrective actions and the low safety significance of the issues, these licensee-identified and corrected violations are being treated as non: cited violations. The closure of the LERs does not address the generic concern for TS compliance. A review of LERs issued as of April 1996 revealed that there have been a number of LERs that have dealt with TS compliance problems relating to questionable interpretations. This area is of current interest for further NRC review. (U3.08.1)

Maintenance

A review was conducted of the preparation and planning activities associated with the retrieval of a hatch bolt from the Unit 1 standby liquid control (SBLC) tan Nuclear oversight (performance evaluation (PE) group) became aware of the plans to retrieve a hatch bolt from the SBLC tank'and raised a number of questions concerning the use of an automated work order in place of a special procedure. The lack of clear guidance on when a special procedure is required resulted in significant resistance from the line personnel to PE concerns about using a work order to perform the work. The decision was made by plant management to develop a special procedure for the bolt retrieval. (U1.M3.1)

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At Unit 1, the (icensee's corrective actions were appropriate to address concerns with the adequacy of procedural guidelines for determining quality control involvement in safety-related work activities. This closes a previous unresolved item concerning this issue. As feedback to the package development process, the open item package had most of the requisite information. (U1.M8.1)

e Contrary to Unit 2 technical specifications, during preparations for a surveillance, operators mistakenly aligned all three high pressure injections to the reactor coolant system. This licensee identified concern was characterized as a non-cited violatio (U2.M8.2)

e A comprehensive self assessment of the Millstone 3 IST program documented broad scope problems that constituted a violation of 10 CFR 50.55a(f). The licensee-identified violation was not cited because the causes for the program f ailures were l

being addressed adequately, and individual test discrepancies were being tracked and resolved appropriately. (U3.M1.2)

e The Unit 3 pressurizer safety / relief valves and main steam safety valves were tested in accordance with Code requirements. A followup item was opened regarding the potential that relief valve testing to the valva " simmer" point may be

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nonconservative. For other Code Class 2 and 3 relief valves, set pressure adjustments made to account for differences in bench test and normal operating

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ambient temperatures need to be justified by test per OM 1. (U3.M3.1)

e Unit 3 acceptance criteria established for IST of safety-related pumps met or exceeded Code requirements. Equipment or procedure changes will be needed to meet Code requirements for repeatability of test reference values, or NRC relief to use broader tolerance bands will be needed. (U3.M3.2)

e' The Unit 3 power-operated valve exercise tests met or exceeded Code requirements, and use of the motor power monitor diagnostic system was commendable. Nonintrusive testing of check valves also was noteworthy, but more documentation was needed to meet GL 89-04 requirements. Additional manual valves may need to be added to the IST program, even if their safety functions are passive. (U3.M3.3)

e A review of ARCOR coating application work orders revealed that on six separate occasions the recoat window was exceeded. The collective procedural noncompliance indicates both an individual and departmental control performance problem in that it demonstrates a low standt.rd for following procedures and a lack, of management oversight for this critical evolution. This failure to follow procedures is a violation of technical specifications. (U3.M1.4)

e An apparent violadon was identified for Units 1,2, and 3 pertaining to the implementation of the systematic approach to training for technical training programs. We found the overallimplementation of these programs to be generally inadequate to ensure continued qualification of technical and non-licensed personnel vi

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to perform in-plant work. Specifically, the licensee failed to properly evaluate trainee mastery of tasks and conduct training program effectiveness evaluation (U3.M4.1)

Engineering

At Unit 1, the initial inspection of the A and B reactor water cleanup system filter cubicles failed to identify discrepancies with pipe supports in the areas. The licensee's initiative to access and inspect normally inaccessible areas is an important mechanism to monitar the material condition of the plant. However, clear expectations need to be developed concerning who conducts these inspections an how the inspections are to be performed and documented. This issue is unresolved pending NRC review of the corrective actions and completion of the preventative maintenance program development for normally inaccessible areas. (U1.E1.1)

The testing of the Unit 1 emergency diesel generator (EDG) was well controlled with an appropriate level of station management involvement. As issues arose they were assessed and handled in accordance with station procedures and policies. At the end of the inspection period, the EDG testing was continuing. With respect to the preparation and procedure development, plant management's intervention early in the process resulted in improvements in the overall reatoration process for the diesel. (U1.E1.2)

e Unit 1 has approximately 38,000 components currently in the production i maintenance management system (PMMS) database. As part of the NU l Performance Enhancement Program (PEP) in the early 1990's, a contractor to NU l reviewed these components and through the material, equipment, and parts lists j (MEPL) program downgraded about 1450 from safety related (SR) to non-safety-

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related (NSR) in late.1994. It was later determined that this downgrade process had j not been properly performed. Thus about 350 of the downgraded components were l reverted back to SR on an emergency MEPL evaluation. Unit 1 currently has plans l to redo all the system level MEPLs before plant startup, but due to lack of resources has not begun this effort yet. As outage work is ongoing in Unit 1, individual component and part MEPL evalut tions are being performed as necessary to support the work and issuance of parts. (U1.E3.1)

e Since 1993 at Unit 2, numerous licensee events reports, adverse condition reports, and NRC enforcement actions have discussed concerns whether air operated valve actuator springs are adjusted to apply sufficient force for the valve to perform its intended safety function. . Escalated Enforcement item (EEI) 50-336/96-201-25 was created to address inadequate licensee corrective action regarding the issue. NRC review of the eel revealed that licensee corrective actions continue to be inadequate in that the scope of the review was limited to containment isolation valves rather

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than all safety-related air operated valves. This eel remains open. (U2.E8.1)

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At Unit 2, the licensee has satisfcctorily resolved the potential for leakage of the fire protection piping joints in the vital switchgear rooms during a seismic event by replacing the Vitaulic couplings on the piping with welded flanges. (U2 E8.4)

Review of the MEPL program implementation at Unit 2 indicated that two unit-specific items require followup inspection: (1) In 1994,998 components were downgraded from safety related (Category 1) to non-safety-related. Af ter a number of these downgrades were found to be inappropriate, in 1995 and 1996 all of the downgraded components were upgraded back to safety-related. The licensee reviewed the work performed while the components were downgraded and found 7 examples where non-safety-related parts were installed. The licensee is currently dispositioning these items; and (2) The licensee is also in the process of evaluating whether parts classified as ' Undetermined' and non-safety-related which have no MEPL have been inappropriately installed. (U2.E8.5)

The licensee's basis for determining that the Unit 2 main steam check valves are non-safety-related was found to be acceptable. However, concerns regarding recurrent inservice testing failures of these check valves is considered unresolve (U2.E8.6)

Four issues were identified during a review of the Millstone MEPL program. These l ltems pertained to 1) potential for non-safety related parts to be installed in safety ~

I related components,2) potential failure to assess the impact of downgrading a l component in the quality assurance program,3) potential not to consider normal cparations and abnormal operational occurrences as part of safety related classifications, and 4) an incomplete PMMS database. (U3 E3.1)

Unit 3 has approximately 60,000 components in the PMMS database, of which about 19,000 are safety-related and 3,000 are augmented quality. During PEP reviews a number of components were originally identified for downgrade, however this action was stopped in Unit 3 before being implemented as a result of lessons learned on Units 1 and 2. In 1996, Unit 3 began MEPL bill of material evaluations for all safety related components that have ever had any work performed on the As part of this effort, whenever non-safety related or undetermined parts are reclassified to safety related, a full work history is performed to ensure acceptable quality of parts in these components. Five additional issues were identified during a review of specific MEPL components and the CVCS system. (U3.E3.3 and E3.4)

The inspector reviewed a Unit 3 adverse condition report that addresses the RHR heat exchanger bolting susceptible to boric acid attack and the actions taken by the licensee .o remove an unsecured structural member installed above safety-related components and to prevent future installations of this nature. The inspector concluded that the licensee's corrective and preventive actions were adequat (U3.E8.1 and E8.2)

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An apparent violation was identified for Unit 3 pertaining to recirculation spray system design errors which resulted in operation outside the design basis and system inoperability. (U3.E8.4)

Plant Support-

The licensee has created a framework at Units 1 and 2 to implement an effective ALARA program. The lack of an effective work control and planning process, together with the absence of a unit ALARA committee still exists at Unit (IV.R1.2)

e Unit 1 management sponsored plant " supervisors walk arounds" in order to raise the health physics awareness of supervisors observing day to day work activities in the field. The walk-around tour was extremely informative and provided good insights into radiological waste reduction. The initiative was well received by the Unit 1 supervisors and will be expanded to included additional areas such as Security and /

Nuclear Oversight. (IV.RS.1)

Significant improvement was found regarding oversight and organization of the fire protection program. Although planned corrective actions were found to be comprehensive, further.NRC review is necessary to verify implementation. (IV.F1.1))

The fire brigade functioned effectively during the observed fire drill and was well prepared to combat fires. Significant improvements were demonstrated by the -

Training and Site Fire Protection departments, including robust command and.

t control, teamwork, support provided by Operations, and a good drill critiqu (IV.F4.1)

: An improvement in.the quality.of assessment provided for the fire protection program was noted. (IV.F7.1)

Overall, performance of the Site Emergency Response Organization (SERO) was good. Simulated events were accurately diagnosed, proper mitigation actions were performed, emergency declarations were timely and accurate, and offsite agencies were notified promptly. Protective action recommendations to the State of Connecticut were correct and timely. Additionally, the information presented during the management meeting was informative and indicates that the corrective measures being taken are appropriate. No exercise weaknesses, safety concerns, or violations of NRC requirements were observed. (IV.P4.1)

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L Report Details Summarv of Unit 1 Statum Unit-1 remained in an extended outage for the duration of the inspection period. The

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. licensee continues to implement configuration management program (CMP) activities, .

engineering reviews, and docketed correspondence assessments to' verify compliance with .

the established design and licensing basis of the unit. The successful completion of these activities is required by NRC order prior to restart of the unit. While there is a reduction of

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s restart activities at Unit 1, through the end of this year, configuration management program

- activities continue. Following a major reduction of the contractor work force for the CMPi project, approximately 35 plant personnel from operations, engineering, and maintenance

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were temporarily assigned work on the CM U1.1 Operallent U101 Conduct of Operations 01.1 General Comments (71707)

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Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoingj plant operations. During this period the inspectors reviewed activities associated with the:

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restoration of the service water system and the emergency diesel generator, both'of which : _

were being restored following an extended outage for maintenance.and plant modification:

- work. There was a significant effort on the part of the Unit 1 staff to return these systems safely and efficiently to an available status for shutdown risk considerations. This effort is discussed in detailin Sections U1.01.3 and U1.E1.2 belo .2 Ooerations Deoartment Command and Control

. Insoection Scone (71707)

Tho' position of. assistant operations manager was eliminated following the implementation of the recovery organization at Unit 1 in October 1996.- Subsequently, the recove,y team re-instituted the position and required that the shift managers report directly to the assistant operations manager. Currently, the operations manager holds a Unit 1 senior reactor operator (SRO) license, fulfilling the requirement of_. Technical Specification (TS)

6.3.1.a., Facility Staff Qualifications. The inspector observed unit operations and

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conducted interviews with a number of shift managers in order to determine if there were clear expectations for command and control within the department. This was particularly-important since the shift managers report to the assistant operations manager and the operations manager holds the TS required SRO license, b Observations and Findinos s On June 26r 1997/ the inspector informed the Director, Unit Operations that there -

- appeared to t;e a problem with command and control within the Unit 1 operations department. This was based on observing unit operations and interviews with a number of shift managers. who expressed a concern with the day to day direction for departmental I

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operation. There was confusion around the operations manager fulfilling the TS SRO license requirement, and the role of the assistant operations manager they were now required to report to. This was a new reporting requirement, and a change from the previous responsibility of the assistant, which was more of an administrative positio The Director, Unit Operations was unaware of the concerns of the shift managers. By the end of June, the operations manager, at the request of the Director, interviewed each of

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the shift managers and confirmed that there was a problem in the operation department -

~ with respect to command and control' The operations manager determined that some_ shift

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managers expressed a concern about the operations manager not being included in the-decision making process and policy making for the department. Some shift managers complained of receiving contradicting direction in the simulator and during classroom training, from the operations manager and the assistant operations manager. Shift managers were not clear on management's expectations, how they were communicated, and the implications if they were not met, in response to this concern, the operations department performed a "new reporting relationship review," and discussed all of the issues and concerns identified by the inspector and the operations manager. The Director, Unit Operation, operations manager, . ~

assistant operations manager, and the five on-shift shift managers were present for this <

review. A plan was developed following the discussions, which included: 1) revising Operations Manual,1-OM 3.1, to clearly define the role of assistant operations manger; 2)

solicit feedback from shift rnanagers routinely to determine if issues are being effectively

[ addressed; and 3) continue improving communications to assure alignment within the departmen The inspector conducted follow-up interviews with the shift managers and received positive comments about the "newireporting relationship review," and the resolution of the issue The operations staff was responsive to the inspector's concerns, performed their own review, and arrived at an adequate solution to the problems. A condition report (CR M1-97-1770) was initiated to document the concerns and track the corrective action Conclusion Recent changes within the operations department required the shift managers to report to the assistant operations manager, a new reporting requirement and a change from the previous responsibility of the assistant, which was more of an administotive positio Following concerns raised by the inspector, operations management N 4 ken steps to -

ensure that the roles of the operations manager and the assistant operation manager are clearly defined, including the new reporting structur i

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01.3 Service Water Svstem Restoration insoection Scoce (717071

,The inspector reviewed the restoration process for the service water system following an extended mahtenance outage. The restoration included the completion of special procedure, SPROC 951-26, " Service Water System Outage (IPTE)." The special procedure

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was required to establish plant conditions to support the maintenance of the service water-system piping to the reactor building closed cooling water heat exchangers and the turbine'

building service water piping, Observation and Findinos During a review of the restoration process for the service water system, the inspector determined that the operations staff was not using a new cperation departmental

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instruction,1-OPS-6.32 " Millstone Unit 1 System Readiness Review," which would have enhanced the restoration process. This instruction was developed to define the process fer assessing and documenting the restoration of a system and provide guidance on

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documenting and resolving discrepancies identified during the system walkdown process. J The instruction was developed in response to earlier NRC concerns with the lack of a '

methodology the returning systems to service. The instruction provided a formal proces )

for returning a system to an operable or available status.

!- Operations management had formed a team to oversee the operations' portion of the service water system restoration. Lacking guidance on how to accomplish this task, the team choose to use the " equipment return to service" departmental instruction, which was a two page instruction applicable to returning a piece of equipment to operable statu Further inspection identified'that a service water restoration plan had been developed,'

which identified responsibilities for a project sponsor and departmental leads from operations, engineering, maintenanen, and planning. The project sponsor was given the responsibility of providing management oversight of the system restoration activitie Discussions with the project sponsor, a maintenance manager, indicated that this person was not aware of his overall responsibility as defined in the plan, but rather considered himself a management support lead. He considered his responsibility to ha the completion of the physical work and turn over of the system to operations. While a restoration pian was developed, it doesn't appear that it was implemented. A CR (M1-971686) was initiated to document the lack of clearly defined roles and responsibilities, and the lack of i

.an identified point of-contact to coordinate all the required activities to restore the syste !

A meeting was held between operations and engineering department management to assign responsibility for performing the specific steps within 1-OPS-6.32. Additionally, a self-assessment was conducted following the service water restoration to identify several areas for improvement. The individuals involved in the upcoming emergency diesel

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generator (EDG) recovery activities were also present during the self-assessment meeting, to gain.some insight into'the planned EDG recovery work. The self-assessment ,

recommendations were documented in a CR (M1-97-1723),

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The inspector observed the service water system recovery activities from the control roo Pre-start briefings were well coordinated and assignments and responsio' ilities were discussed with the plant staff. A half-hour into the evolution, the shift manager identified that the management test lead (MTL) was not on sitei when he tried to contact the MTL with a question concerning the system restoration. The shift manager suspended the evolution until the MTL was on site. The restoration activities were controlled under administrative procedure ACP-QA-2.27, " Infrequently Performed Test or Evolution (IPTE)."

While ACP-QAO.27 states that the MTL is responsible for continuous responsibility (whether on site or off site) for IPTE oversight, the shift manager determined that it was -

appropriate for the MTL to be on site for the dynamic portion of the evolutio Additionally, during this time nuclear oversight questioned the adequacy of termination criteria in the restoration procedure. This issue was evaluated and SP 623.13A "Serdce Water Pump Performance Test" was added to ensure that the service water system was performing its intended function, once it was placed back in service. This toter caused a problem since test conditions specified in the performance test could not bo met because the test was normally performed during normal operating conditions. The restoration activities resumed the following da ,

[ Operations management assigned a reactor operator (RO) to control and monitor the t

activities from the control room. The RO did an excellent job coordinating the step-by-step activities wi*h the field operators via the radio, and keeping the unit supervisor informed _of each step of the restoration. There was also good coordination between operations, the l test engineer, and the MTL. The evolution was also observed by the assistant operations i I

manager and nuclear oversight. Following the completion of the evolution the termination criteria was again revised to remove the service water pump performance test and in its place service water operating parameters such as pump amperes, vibration, and discharge pressure were added to ensure that the system was operating properly. The inspector noted that the service water system normal operating procedures did not contain appropriate guidance for determining normal system operating parameters. This issue was identified during the development of the termination criteria stated above. A CR (M1-97-1713) was initiated to document this concer Conclusion During a review of the restoration process for the service water system, the operations staff was not initially using a new operation departmentalinstruction,1-OPS-6.32

" Millstone Unit 1 System Readiness Review," which would have enhanced the restoration-by providing a formal process for returning a system to an operable or available statu Additionally, an individual assigned as the overall management lead for the evolution did not function in that capacity. The reactor operator assigned to control and monitor the activities from the control room did an axcellent job coordinating the step-by-step activities with the field operators, and kept the unit supervisor informed of each step of the restoration. There was also good coordination between operations, the test engineer, and

the management test leadi The inspector noted that the service water rormal operating procedures did not contain appropriate guidance for determining normal system operating parameters following the system restoratio l

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U1.II Maintenance U1 M3 Maintenance Procedures and Documentation M3.1 Standbv Liould Control Tank Insoection Scooe (62707)

The inspector reviewed the preparation and planning activities associated with the retrieval of a hatch bolt from the standby liquid control (SBLC) tank. While sampling the SBLC tank on June 19,1997, the threaded rod that holds the tank cover in place unscrewed and dropped into the tank (CR M197-1520). Observations and Findinas Unit 1 nuclear oversight (performance evaluation (PE) group) became aware of the plans to retrieve a hatch bolt from the SBLC tank at the 6:30 morning work control meeting, on June 24,1997. After some discussion with the chemistry supervisor, it was apparent that j- the work was going to be performed under an automated work request (AWO), in a day or '-

} two, with no pre-job briefing up to that point, no system engineering involvement, and no "

l nuclear oversight involvement. PE suggested that a meeting be set up to bring all interested parties together and discuss the evolution. A number of questions were raised by PE at that meeting concerning the use of an AWO in place of a special procedure, foreign material exclusion (FME) control, material compatibility, and possible chemical interactions between the contents of the SBLC tank and all equipment being used for retrieving the hatch bol Subsequent to the initial meeting, the inspector noted significant resistance trom the line personnel to PE concerns about using an AWO to perform the work. PE's concerns included the fact that this was an infrequently performed activity. DC 1, " Administration of Procedures and Forms," states that special procedures are prepared as necessary to support infrequently performed activities which are not to be included in the permanent list of station procedures. There were discussions about whether or not this activity was infrequently performed, e.g., removing something from a tank. PE was concerned that since this was a category 1, safet) system, and the tank contained heater coils and air spargers, special precautions were needed to address these issues, which would require involvement by system engineering. The line personnelinsisted on using an AWO and PE provided a large number of comments following a review of the draft AWO At that time. .

the line planned to perform the work using a revised AWO, which included PE's comment After continued dialogue between the line personnel and nuclear oversight that lasted approximately two weeks, the decirion was made to open the tank and determine the exact scope of the recovery activities. The inspector observed the activity, which was appropriately controlled, FME controls were in place. Following.that activity, plant management determined that a special procedure would be written, and work would be performed in August 199 ____ _j

_ _ _ . _ - . _______ _ ___---_ - _-

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.. . Conclusion LThe inspector reviewed the preparation and planning activities associated with the retrieval of a hatch bolt from the standby liquid control (SBLC) tank. Nuclear oversight

- (performance evaluation (PE) group) became aware of the plans to retrieve a hatch bolt from the SBLC tank and raised a number of questions concerning the use of an automated work order in place of a special procedure. -The lack of clear guidance on when a special procedure is required resulted in significant resistance from the line personnel to PEL ,

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concerns about using a work order to perform the work.' The decision was made by plantg management to develop a special procedure for the bolt retrieva U1 M8 Miscellaneous Maintenance issues M8.1 (Closed) Unresolved item (URI) 50-245/94-014-03: Quality Control involvement in Safetv-related Work Activities (SIL 108 UPDATE) Insoection Scone (62707)

-

The inspectors reviewed the licensee's findings and corrective actions associated with the?

determination of quality control involvement in safety-related work activities and for .

determining when inspection hold points were require Observations and Findinas The unresolved item concerned maintenance on EDG air start system solenoid-operated valves (SOV). The maintenance was a rebuild activity and the inspector found that the work was performed without a PORC-approved procedure, and there 'was a violation issued

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for that finding. 'In addition,'the procedure in place at the time, ACP-QA-2.02C, Work Control, provided guidelines for determining quality control involvement in safety-related work activities and for determining whether inspection hold points were required. The

_ planner's conclusion that no quality services department involvement was required for the SOV maintenance appeared to have been consistent with those guidelines. At the time of the inspection, the inspector was concemed with the adequacy of those procedural guidelines. Nuclear oversight needed to reevaluate the policies and guidelines set forth in ACP-QA-2.02C A URI was initiated to document this concer The reevaluation was completed and the licensee implemented a new procedure, WP 8003,

'" Unit 1. Work Package Planning,". which included a step that provided definitive guidance

' on when work orders required a quality assurance (QA) review. The guidance was changed from listing six activities that need QA involvement, which is open to interpretation, to a " management by exception" concept, listing the 23 activities that do 1 not reouire QA involvement, with all others requiring a OA review. Additionally, as part of

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.the recovery plan for nuclear oversight, two procedures were developed that gave nuclear E ,

oversight ownership of the hold point program and responsibility.fo'r. assigning hold points-on all AWOs. A QC tech support group was established to provide this function, with'all '

AWOs being reviewed by this group prior to implementation,

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7 Conclusions The NRC concluded that the licensee's corrective actions would address the adequacy of

. procedural guidelines for determining quality control involvement in safety related work -

activities. This item is closed. As feedback to the package development process,' the inspector concluded that the open item package had most of the requisite information, however, the inspector needed to consult the preparer of the package to understand how the information addressed the issu U1.Ill Engineering U1 E1 Conduct of Engineering E A and B Reactor Water Cleanuo System Filter Cubicles Insoection Scooe (37551)

The inspector reviewed a video tape record of an inspection that was conducted in the A o

and B reactor water cleanup (RWCU) system filter cubicles. On June 16-17,1997, the A' +

and B RWCU filter entrance floor plugs were removed for an inspection of the areas. The -

inspection was part of the licensee's program for entering normally inaccessible area Observations and Findinas The work activity was performed under an AWO with a system engineering sign off for the completed inspections. A video tape record of the inspection was completed and the inspector requested a copy for review. While reviewing the tape, the inspector noted an object wedged between twb pipes in a pipe sleeve in the B filter cubicle. The system engineer was contacted and the inspector was informed that the discrepancy had not been identified or documented in a condition report. The inspector also reviewed the completed AWO that stated that two pieces of wood and one pen were removed from the floor of the

'B' cubicle; no additional discrepancies were noted. The system manager, his supervisor, and the inspector reviewed the video tape and identified some additional discrepancies of the same type, wedges in pipe sleeves. A CR (M1-97-1678) was initiated as a result of that review to document the discrepancies and corrective actions, and an assignment was added to the CR to deterrr.ine why the initial inspection failed to identify the discrepancie Discussions with the system manager responsible for developing a strategy for the inspection of normally inaccessible areas, indicated that a preventive maintenance program -

was being established to ensure that these areas are inspected on regular basis. All but one of the sixteen areas designated as normally inaccessible at Unit 1, are inside structures considered within the NRC Maintenance Rule 10 CFR 50.65, in-scope populatio Therefore, these areas are subject to a structuralinspection to be conducted every two

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refueling cycles to ensure compliance with the structural monitoring provisions of the .

- maintenance rul . . .. .. . . .. . .. . .. ..

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I 8 Conclusion?

The inspector concluded that the licensee's initiative to access and inspect normally inaccessible areas is an important mechanism to monitor the material condition of th plant. However, clear expectations need to be developed concerning who conducts these inspections and how these inspections are to be performed and documented. This issue is unresolved (URI 245/97 202-01) pending NRC review of the CR corrective actions and completion of the PM program developmen E1.2 Emergenev Diesel Generator Testina Insnection Scooe (37551)

The inspector reviewed the restoration process for the emergency diesel generator (EDG)

following maintenance and modification work, Observations and Findinas During a PORC meeting conducted on June 4,1997, four different special procedures were!

proposed for the restoration of the EDG following maintenance and modification work, At -

that point, plant management determined that the staff would need to perform a review of all the EDG post-maintenance testing, to identify any overlapping testing that was required for the EDG restoration. This was needed to prevent duplication of the testing and provide an efficient methodology to comp!ste the required testing. A special procedure was created following the review under administrative procedure ACP-QA 2.27, " Infrequently Performed Test or Evolution (IPTE)," to encompass all the work required for restoratin The special procedure consisted of six phases including monitoring, testing, and data gathering steps. The test included post maintenance and modification testing and limited the number of EDG test starts by performing the testing in a logical, efficient manne The inspector observed the initial briefing for the test conducted on July 15,1997, by the management test lead (MTL) and the test engineer, and found that it was comprehensive and provided an good overview of the IPTE. The termination criteria and responsibilities for plant personnel were explicitly stated. A number of issues that were raised at the briefing and were reviewed and appropriately added to the procedure. For example, the reactor operator (RO) suggested adding a step to line up the in service systems to the S1 power supply prior to the start of the test. This had been discussed during the briefing, but the RO noted that it was not part of prerequisite steps in the IPT The inspector noted that the lessons learned from the earlier service water restoration were included in this evolution, including identifying a management lead individual responsible for the oversight of the system restoration activities, and the use of 1-OPS 6.32 " Millstone

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Unit 1 System Readiness Review."

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9 Conclusions The testing of the emergency diesel generator was well controlled with an appropriate level

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of station management involvement. As issues arose, they were assessed and handled in .

accordance with station procedures and policies. At the end of the inspection period, the EDG testing was continuing With respect to the preparation and procedure development, the inspector found that management's intervention early in the process resulted in improvements in the overall restoration process for the diese U1 E3 Engineering Procedures and Docuaentation E Unit 1 MEPL Status Uodate The overall site matarial, equipment, and parts lists (MEPL) program was reviewed; comments and discussion that apply to all three units are provided in Section U3 E This section provides Unit 1 specific discussions onl Unit 1 has approximately 38,000 components currently in the production maintenance f ~

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management system (PMMS) database. As part of the NU Performance Enhancement -

Program (PEP) in the early 1990's, a contractor to NU reviewed these components and through the MEPL program downgraded about 1450 from safety related (SR) to non safety-related (NSR) in late 1994. It was later determined that this downgrade process had not been properly performed. Thus about 350 of the downgraded components were reverted back to SR on an emergency MEPL evaluation. The other 1100 were each given a full MEPL evaluation with the following results. About 20% were converted back to SR and the remaining 80% were determined to be appropriately downgraded to NSR.

Unit 1 currently has plans to redo all the system level MEPLs before plant startup, but due l to lack of resources has not begun this effort yet. As outage work is ongoing in Unit 1, individual component and part MEPL evaluations are being performed as necessary to support the work and issuance of parts. Unit 1 has not decided on the level of MEP evaluations to be performed for component Bill of Materials (BOM). Currently, full BOMs are not being completed even for components that are being worked on AWOs Unit 1 is performing full historical reviews of work history for components or parts that are upgraded from NSR to SR but not for items upgraded from Undetermined (U) to NS .

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Renort Details Summerv of Unit 2 Status Unit 2 entered the inspection period with the core off loaded. The unit was initially shut -

--down on February 20,1996f to address containment sump screen concerns and has remained shut'down to address an NRC Demand for Information 110 CFR 50.54(f)] letter -

requiring an assertion by the licensee that future operations are con' ducted in accordance with the regulations, the license, and the Final Safety Analysis Repor U2.1 OperatlQnt U201 Conduct of Operations 01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious. Operator performance was good in evaluating shutdown risk by maintaining

- awareness of plant conditions and equipment availability. In particular, on July 14,1997, operators exhibited a good questioning attitude regarding the planned removal from service ?

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of the spent fuel pool area ventilation supply fan, F-20. Operators noted that procedure OP 2264, " Conduct of Outages," was unclear whether the shutdown risk " Key Safety Function" for spent fuel pool area ventilation boundary would remain " Green" with fan F-20 removed from service. A condition report was generated to address the concern and-procedure OP 2264 was changed before proceeding with planned maintenance activities on fan F-20. Other noteworthy observations are detailed in the sections below.

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) 01.2 Removal of Non-conservative Technical Soecification Clarifications from the Technical Reauirements Manual a, insoection Scoce (71707)

The inspector evaluated the licensee's efforts to remove non-conservative technical specification (TS) clarifications from the technical requirements manual (TRM). Observations and Findinas The licensee performed an evaluation the 27 technical specification clarifications and "

categorized 7 of them as more conservative,10 as less conservative,-and 10 of them being neutral as compared to the corresponding technical specification. On July 15,1997, the licensee completed their effort of removing from the TRM all 10 technical specification clarifications that were categorized as less conservative. The inspector verified that each of the non-conservative TS clarifications that could be considered a TS non-compliance was ;

appropriately reported to the NRC in accordance with 10 CFR 50.7 Conclusion The licensee initiated effort in removing 10 non-conservative technical specification clarifications from the TRM was goo _

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01.3 Timeliness of Corrective Actions - Condition Reoort Backtoo Insoection Scoce (71707)

The NRC evaluated the timeliness in which the licensee completed corrective actions associated with Unit 2 condition reports (CRs). Observations and Findinos Timeliness for completion of corrective actions has been a longstanding concern at Millstone. Having a CR backlog in itself is not a reflection of poor performance because as the threshold for writing CRs decreases, the CR backlog will increase accordingly. The concern is the number of CRs that are not closed in a timely manner. To help provide the NRC some sense of the licensee's progress in addressing the timeliness concern, the licensee was asked to provide the number of CRs having outstanding corrective actions that are greater than 120 days old. Although the NRC does not consider 120 days a level of excellence nor is it acceptable when addressing immediate safety concerns, it does provide some understanding of licensee management effectiveness in addressing the corrective action timeliness issu At the end of the current inspection period, ti.ere were 780 CRs greater than 120 days old i

_that have not been closed which is a decrease from 828 CRs at the end of the last-inspection period. Out of the 780 CRs currently greater than 120 days old,200 of them were initiated in 199 . DEPARTMEN .

CRs OLDER THAN ' - l 1997 CRs OLDER -

120 DAYS - THAN 120 DAYS Operations 48 10 Design Engineering 255 62

- Technical Support 182 26

. Work Planning 25 8 Maintenance 54 26 I&C 28 7 Safety / Licensing 47 8 Other .141 53 TOTAL' 780 200

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12 Conclusiorm -

The total backlog of 780 CRs that are greater than 120 days old indicates that. timeliness for completing corrective actions continues to be a concern. The backlog of 1997 CRs

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greater than 120 days old is of greater concern be':ause it reflects the performance of the -

new management organization. The new management planned to demonstrate a higher standard by dispositioning newly' generated CRs in a timely manner while establishing a plan for working off the CR backlog that existed when they arrived. However, the backlog of 200 CRs greater than 120 days old that were generated in 1997 indicates that the new management is also ineffective in addressing the corrective action timeliness issue which is considered a significant weakness. As discussed in NRC Inspection Report 50-336/96-04, timeliness and effectiveness of corrective actions is an area in which the licensee must demonstrate sustained improved performanc U2 03 Operations Procedures and Documentation 03.1 Henctor Buildino Closed Coolina Water Surae Tank Minimum level Insoection Scoce (71707)

The inspector evaluated the licensee's administrative controls for maintaining the reactor building closed cooling water (RBCCW) system surge tank level, Observations and Findinos The RBCCW surge tank, which is utilized by both facilities (trains), is normally maintained at 50 percent level by an automatic makeup valve in the primary makeup water syste The RBCCW surge tank has'en intemal vertical weir that rises to the 37 percent level which allows draining of one facility while maintaining the other facility in service. To support maintenance on RBCCW system components, the licensee had drained facility 1 and was maintaining level on the facility 2 side of the RBCCW surge tank was than 32 percent. Operators were periodically opening the primary makeup water supply to facility 2 to account for minor system leakage. However, the inspector found that the required RBCCW surge tank level band was not proceduralized nor was it specified on the Shift Turnover Report. One control room operator stated that operators had been filling the RBCCW surge tank when level reached approximately 20 percent. The inspector was concerned that with an undefined minimum surge tank level, RBCCW system operability could be affected due to potential net positive suction head (NPSH) concerns for the RBCCW pump The inspector discussed this concern with operations management and as an interim measure, the licensee added a surge tank level band of 24 percent to 32 percent to the Shift Turnover Report. Subsequent review by plant engineering indicated that as long as ( there is a visible level la the surge tank, there would be sufficient NPSH for the RBCCW pumps. Nevertheless, the licensee agrees that the RBCCW level band should be

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proceduralized and is in the process of evaluating the necessary procedure changes, i

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.c 13 Conclusion :

Although the licensee determined that there would be sufficient NPSH available to the

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. RBCCW pumps, the failure to evaluate and proceduralize the level band that operators _

should control RBCCW surge tank level was considered a weaknes U2.ll Maintenance U2 M8 Miscellaneous Maintenance issues MD.1 (Closed) Insoector Follow un item 50 338/95 201 03: Procedure Level of Use Deslanation (SIL 8 Individual item Closed)

e, jntger tiori Ccone (929D2J ;

The scope. I viis inspection included a review of Inspector Followup ltem (IFI) 50 336/95-201 0 :

, Observations and Findinos This item concemed the fact that most maintenance and surveillance procedures were classified as " General Use" versus " Continuous Use." The procedure Level of Use designations are defined in procedure DC 4, " Procedural Compliance," as follows: i Continuous Level of Use Procedure

A procedure that controls a work activity that is critical, complex, or involves infrequently parformed evolutions or activitie * Requires step-by step use to prevent immediate effects on nuclear or personnel safety and plant reliabilit General Level'of Use Procedure

- A procedure that involves evolutions or work activities on plant equipment or has multiple actions required to perform a task or task * Procedure must be referred to as necessary during the performance of the work activity to ensure the evolution is performed correctl * The level of detail allows the user to read an entire sequence and perform it before referring to the procedure again to confirm the complete task and prepare for the next task or sequence.

I information Level of Use

A procedure that involves administrative or technical evolutions or processe * Procedure requires periodic review for familiarity but is not required in the fiel The inspector found that only five mechanical and electrical procedures had been changed from " General Use" to " Continuous Use" during the past two years which reflects licensee management's view that the " General Use" category is adequate for most procedures,

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Procedure DC 4 specifies that the Level of Use indicates the minimum required degree of reference to the procedure during portions of the work activity and does not alter expectations for procedure adherenca, Conclusion The NRC considers IFl 50 330/95 20103 to be closed based on: (1) There is no specific regulatory requirement that defines or mandates procedure Level of Use classification: (2)

Although there have been examples of procedural adherence issues documented in NRC inspection reports since this IFl was opened, there were no documented examples of where the procedural noncompliance could be attributed to the Level of Use designation; and (3)

Inspector observations indicate that surveillance procedures are generally referred to on a step by step basis even though most surveillances are " General Use." Even though this item is being closed, the NRC considers procedure Level of Use to be an area where management standards and expectations should be promulgated, particularly with surveillance procedums to ensure understanding by the licensee's staf M8.2 (Closed) Licentee Event Reoort 50 336/97-04: Hiah Pressure Safetv Inlection (HPSil Eymo Allonment Insoection Scooe (92902)

The inspectors reviewed the corrective actions taken by the licensee to prevent recurrence of the event described in the subject LER, Observations and Findinga On January 23,1997, the licensee discovered that three HPSI pumps were aligned such that they were all capable of injecting water into the reactor coolant system. The plant was in the refueling mode (Mode 6) with the reactor vessel head removed in that mode plant technical specifications only permit two charging pumps and two HPSI pumps to be capable of injecting into the reactor coolant system (RCS) to prevent an inadvertent RCS overpressurization. The three HPSI pumps were inadvertently aligned, due to personnel error, for approximately 36 minutes during preparations for surveillonce testing. The condition was immediately corrected upon discover Additlenal corrective actions included the revision of all affected surveillance test procedures to include pump alignment requirements. A detailed briefing of the event and causal factors was given the operating shift crews, The inspector reviewed the revised test procedures and the briefing provided to the operators, Conclusions The licensee's corrective actions associated with this LER were determ;oed to be acceptable. The safety significance of this event was minimal because: 1) With the reactor vessel head removed, the inadvertent injection by three pumps could not overpressurize the reactor coolant system; and 2) If operators had not discovered the HPSI pump alignment

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during the shif t, the condition would have been identified during the shif tly performance of the control room operator logs per procedure OPS Form 2014A 2, " Control Room Daily Surveillance, Mode 6 and Defueled." This licensee identified technical specification non-compliance is being treated as a Non Cited Violation, consistent with section Vll.B.1 of th NRC Enforcement Pollev. This LER is close U2.lli Engineering U2 E8 Miscellaneous Engineering issues E (Closed) IFl 50-336/93-20-05 & LER 50-336/9711 and (Uodate) eel 50 336/96-20125: Testino of Dual Function Valves (Update . Significant item List No. 30) Insoection Scoce (92903)

The inspector reviewad the corrective actions taken by the licensee to address questions regarding testing of dual function air operated valves. The licensee defines dual function valves as those valves that have an isolation function at containment design pressure and at the normal system operating pressure, Observations and Findinas As discussed in Licensee Event Report 50-336/93 23, in June 1993, the licensee experienced problems with leakage past the letdown isolation valves 2 CH 089 and 2 CH-515 while attempting to establish isolation to support repairs to a manual stop valve in the line. The plant was at normal operating pressure (2250 psig) at that time. The cause of the leakage was found to be improper adjustment of the spring preload on the air operators during prior maintenance. The LER documented the immediate corrective actions taken which included the adjustment of the affected valve operator spring preloads and verification of the isolation capability at normal reactor coolant system pressure. Th6 LER also noted that a maintenance procedure had been developed for the actuator type used on the affected valves. This procedure included detailed spring bench setting requirement Procedures for all dual function valves were to be completed prior to the next refueling outage and retest requirements involving verification of isolation against normal system pressure for the valves were also to be define in February 1994, a viutation was cited for the performance of the work on the air actuators without written procedures. At that time, the inspector noted that the violation could have reasonably been prevented by corrective action for a previous licensee finding concerning valve 2-EB 99. The licensee's violation response specified that procedures for pneumatic actuators would be completed prior to May 6,1994. Additionally, the licensee committed to specifying retest requirements to verify valve isolation capability against .

normal system pressure for all valves that function in a dual rol .

.

In June 1995, Adverse Condition Report (ACR) 1935 was written to identify that actions had not yet been taken to implement the commitment to ensure the required isolation of dual function valves against normal system pressure, in response to an NRC inspection finding that the licensee's commitment had still not been completed, in March 1996, ACR 9623 was written to identify the potential that 23 dual function valves may not be set to isolate agains. .iormal system pressure. The licenseo planned to perform as-found testing of the valves following the core off load. Escalated Enforcement item (EEI) 50-336/96 20125 documented an apparent violation for the licensee f ailure to implement prompt corrective action to resolve the dual function valve testing concern, in March 1997, Condition Report (CR) M2 97 0412 was written to document the results of the as found testing. The testing method involved measuring the pressure needed to operate the valve and then using the air pressure results to determine the seating force the

,

valve operator spring was transmitting to the valve dis Following the completion of testing and evaluation of test results,in May 1997, LER 50-330/97 011 reported that 11 of the 23 valves tested were not capable of closing to a leak-tight condition against normal system operating pressure. The corrective actions specified in the LER were to: (1) revise the appropriate procedures prior to entering Mode 4 to ensure that the proper valve control parameters are specified and verified after maintenance that could affect dual function valve closing forces; and (2) adjust the affected valves to ensure they properly close against containment pressure and normal operating system pressure prior to entering Mode 4. The licensee also stated that these actions satisfied the commitment to specify the retest requirements for dual function valve The inspector reviewed the licensee actions taken to date to resolve the issue of inadequate testing of dual function valves. Since the cause of the original problems was attributed to the lack of adequate procedures for performing maintenance on valvo air actuators, the inspector questioned why the concern for adequate closing force would not apply to all air actuators in the plant, not only valves with dual functions. The licensee had not reviewed other air operated valves, in particular those valves that have safety functions, to assess the valve operability. The licensee acknowledgod this concern and prepared Memorandum MM2 97 043, dated July 2,1997, which discusses planned actions to screen, evaluate, and test additional air operated valves to ensure that valves that are critical to the safe operation of the plant are set up properly, Conclusions The NRC concluded that the licensee has established adequate methods for testing the air operated valves to ensure that adequate force is applied by the actuator springs for the valve to perform its function. However, despite numerous LERs, ACRs and NRC enforcement actions that have documented the air operated valve concerns since 1993i--

licensee corrective actions continue to be inadequate in that the scope of the review was limited to the " dual function" valves even though other safety-related air operated valves

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could have the same setup problems. eel 50 336/96 20125 (and Significant items List No. 30) remain open pending:

e NRC review of the completed licensee corrective actions committed to in LER 50-336/97 11; e NRC review of the licensee findings and corrective actions relative to non dual function air operated valves; and, e NRC review of any additionallicensee actions that may result from the resolution of eel 50-336/96 20125. Because eel 50 336/96 201 25 encompasses the technical issues and corrective actions discussed in LER 50 336/9711, the NRC will use this eel to track those issues; LER 50-336/9711 is considered administratively closed, inspector Followup Item (IFI) 50 336/93 20-05 identified a concern that reduced pressure testing of 10 CFR 50, Appendix J, may not adequately assure the leak tight integrity of valves that may be required to close at full reactor coolant system pressure. The inspector noted that the Appendix J testing verifies the valve seating capability at containment design pressure. This testing, combined with additional testing to ensure adequate closing -

force at full system pressure, demonstrates the ability of the valves to function at full system pressure. Since the actions being taken to implement the additional testing are being tracked as discussed above, IFl 50 336/93-20-05 is considered close E8.4 (Undate) Escalated Enforcement item 50-336/96-201 36: Inadeauste Corrective Action Concernina a Ecismic Deslan Deficiency of a Vital Switchacer Room Cooler (Closed - Significant items List No. 33) Insocction Scoce (92903)

The inspector reviewed the licensee's modification to the fire protection piping in the cable spreading area of the turbine building for precluding potentialleakage of the Fire Protection (FP) class 2 piping over class 1 components and the design basis for precluding the unwanted seismic class 2 over 1 interaction in this cable spreading area, Observations and F:ndings On September 29,1995, the licensee's Service Water System Operational Performance (SWSOPI) identified a concern with Vitaulic couplings in a 3" fire protection (FP) pipe located over chiller X 182 in the cable spreading area of the turbine building at elevation 45'-0". The possibility existed that the Vitaulic coupling could have leaked during a seismic event, thus, actuating the moisture detector in the coffer dam around the X 182 chiller which then would close the service water flow to the cooler The inspector reviewed the licensee's records, interviewed the cognizant personnel, and performed a walkdown to ensure that the corrective action that replaced the Vitaulic

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couplings with welded flanges to assure leak tightness of the fire protection system pipe joints was properly implemented. During the walkdown, the inspectar observed that the

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i Vitaulic couplings on the 3" fire protection piping over chiller X 182 located in the cable spreading area of the turbine building had been replaced with welded flanges as prescribed by the entrective action. The rest of the FP piping cppeared to be well supported to withstand a postulated seismic even During the walkdown, the inspector noted that a segment of this FP piping (elbow) has a l 1/4" of clearance from a safety related a cable tray, thereby creating a possible nonconformance with the seismic 2 over 1 interaction criterion. The licensee initiated a condition report to prepare a calculation to evaluate the as found configuration during a postulated seismic event. The inspector reviewed the licensees' calculation No. 97-ENG-01819C2, Revision 0, and concluded that the licensee has performed a detail calculation with a finite element computer model of the subject pipe using a standard computer program. The analysis was performed using the correct parameters from the design basi \

The results showed that the maximum relative displacement between the FP pipe and the cable tray in question is 0.078 which is less than 1/4". Therefore, the existing 1/4" clearance is adequat Conclusion The licensee has satisfactorily resolved the potential for leakage of the fire protection piping joints during a seismic event by replacing the Vitaulic couplings on the piping with wolded flanges. The proposed violation and potential escalated enforcemerit action for this item is still under review by the NR E8.5 (Undate) Escalated Enforcement items 50-336/96-201-42 & 43: Materia!,

Eouioment and Parts List Program (Update Significant items List %.18) Insoection Scone (92903)

The overall site material, equipment, and parts lists (MEPL) program was reviewed; comments and discussion that apply to all three Millstone units are provided in Unit 3 Section U3 E8.1. This section provides Unit 2 specific discussions only, Observations and Findings Unit 2 has approximately 60,000 total components in the plant, of which about 12.000 are safety-related. As part of the Performance Enhancement Program (PEP) in the early 1990's, the licensee reviewed the quality classification of about 28,000 components. In -

late 1994, the MEPL program was utilized to downgrade 998 components from safety-related (Category 1) to non safety-related, it was later determined that a number of these downgrades were not correct. Thus,in 1995 and 1996 all of the downgraded components were upgraded back to safety-related. During the time period that the components were improperly classified, work was performed on them as non safety-related components, creating the possibility that substandard parts may have been installed. To address this concern, the licensee reviewed each of the 400 to 500 automated work orders (AWOs)

that had been performed during this time period on these components to determine if non-safety-related replacement parts had been installed. Seven instances were identified that

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required that nonconformance reports (NCRs) to be issued and various corrective actions to be taken. As of the end of this inspection report period, not all of the NCRs had been fully dispositione As one action to address the various concerns associated ,v th cl'.ssh1catloa of components and the MEPL program, Unit 2 is performing a IFL re wew of all systems and all safety related components. This is being done at the component level and is

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i scheduled for completion in the Fall of 199 MEPL evaluations are not only performed at the component level but also the part level because parts that are not critical for the component to perform its intended safety function may be classified as non-safety related. For each unit, a number of condition t

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reports (CRs) have documented that some parts listed on the Bill of Materials (BOMs) for a safety related component were either classified as ' Undetermined' or non safety relate This raises the question of whether non-safety related parts have been inappropriately l_ installed in safety related components. At Unit 2, licensee corrective actions to address

- this concern included: (1) performing BOM MEPLs prior to working on components during the current mid-cycle outage, and (2) performing a full historical review of work orders of-any part or component that has its MEPL classification upgraded from ' Undetermined' or - '

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non safety related to safety related. The inspector asked the licensee why it was ~

appropriate to limit the historical review to only those parts that have been upgraded because components that have not been worked during the mid-cycle outage, whose BOM MEPL has not been performed, may have had non-safety related parts installed. At the t

close of the inspection period, the licensee was still gathering information to justify their plans, Conclusion Escalated Enforcement items 50-336/96 201-42 & 43 remain open to allow further NRC inspection of the site specific and programmatic MEPL concerns that are summarized in in Unit 3 Section U3 E E8.6 (Ocen) Unresolved item 50-336/97 202-02) Main Steam Check Valves Deslan Adeousev (Closed Significant items List No. 45) insoection Scone (92903)

This inspection involved a review of Adverse Condition Raport (ACR) M2 96-0542, which questioned whether the non safety-related classification of the main steam check valves was appropriate. The check valves are credited in the accident analysis for preventing the blowdown of the intact steam generator in the event of a main steam line break (MSLB)

upstream of the main steam isolation valves (MSIVs).

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20 Observations and Findinas In addressing the ACR, the licensee provided a detailed licensing basis history regarding the

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main steam check valves. There is no licensing basis documentation that specifies >

explicitly whether the check valves are considered safety related or non-safety related.

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However, the seismic classification of the check valves that is explicitly stated in the Final Safety Analysis Report (FSAR) combined with NRC guidance documentation issued af ter

. Millstone 2 was licensed, provides a sufficient basis to conclude that the non safety related classification of the check valves is acceptable. The original FSAR, Section 10.3.2.1,

,' , states that main steam line up to and including the MSIVs are required to be Seismic Class I and all downstream components (which includes the main steam check valves) are considered seismic Class 1 Although the following information is contained in NUREGs that were issued af ter Millstone 2 was licensed, they still provide insights on the staff's position regarding the issue. The NRC discusses and generically accepts the use of non safety related main steam check valves in NUREG-0138, " Staff Discussion of 15 Technical Issues Listed in Attachment to November 3,1976 Memo from Director, NRR to NRR Staff." NUREG 1038, issue No.1, discusses the treatment of non safety-grade equipment in evaluations of postulated steam r line break accidents. Although the main steam checns valves were not the focus of the evaluation, NUREG-0138_ stated that "for the purposes of this discussion, a safety grade component is defined as one which is designated as seismic category I.... The remaining valves in the main steam and main feedwater lines are designated as non-safety grade components...." The NRC notes that for accidents involving spontaneous failures of the secondary system piping, that are not part of the primary system boundary, less stringent requirements are imposed on the quality and design of systems needed to cope with the secondary system rupture Due to their use as a backup to safety related components in the safety analyses, the inspector also reviewed the Inservice Testing (IST) and Inservice Inspection (ISI)

requirements associated with the main steam check valves. The IST program requires that the licensee verify during each cold shutdown that the valve travels smoothly and completely to the closed position as steam plant load is reduced. The inspector reviewed the following:

IST surveillance test SP 21134, " Main Steam System Valves Operational Readiness Test," Rev.10, and the Surveillance Cover Sheet ENG. Form 21134, Rev. 4, which contains the acceptance criterla and which records the data, test acceptability, and .

approvals;

The check valve disassembly and inspection progra The inspector noted two errors in Rev. 4 of ENG Form 21134 with respect to the position of the valves during the test as being fully open or fully closed. The licensee concurred and initiated a procedure change. The inspector also selected recent tests and noted that there have been difficulties with the valves passing the test. The maintenance history for the-valves was also reviewed and the inspector noted a moderate amount of work required to i

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maintain the valves. The inspector reviewed procedure EN 21221, Rev. O, " Check Valve Examination and Testing," which places these check valves in the Priority 3 Group for examination once every five refueling outages. This procedure was placed in a "Do Not

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Use" status as of September,199 Conclusion The licensee's basis for determining that the main steam check valves are non safety-l related was found to be acceptable and Significant items List No. 45 is considered closed.-

The area of inspection, maintenance, and testing associated with these check valves is unresolved and will be further reviewed to ensure that appropriate activities are being accomplished to ensure reliable functionality of the valves. (Unresolved item 50 336/97 202-02)

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Unit 3 Reoort Detalla Summarv of Unit 3 Status

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- Unit 3 remained in cold shutdown (mode 5) status throughout the inspection period.; The -

licensee continued to implement unit recovery activities, while continuing to develop an Operational Readiness Plan directed toward the objectives and milestones leading to both-the physical readiness of the Unit 3 restart and the preparedness for the NRC operational

- readiness inspection conduc On July 16,1997 the licensee notified the NRC that the problem identification phase of its i, Configuration Management Program (CMP) was complete for all 88 plant systems, comprising all Maintenance Rule "in scope" group 1 and 2 systems. As delineated in the NRC Confirmatory Order governing the Independent Corrective Action Verification Program (ICAVP), this pronouncement by the licensee declared all 88 systems available for review and inspection as part of the ICAVP process. During the previous inspection period, the licensee line management had declared readiness for the start of ICAVP activities. After concurrence from the licensee's Nuclear Oversight organization, the ICAVP process at Millstone Unit 3 commenced on May 27,199 As of the end of this inspection period, the NRC had selected all five systems that will be subject to the ICAVP contractor (four "in scope" systems) and NRC team (one "out of-

. scope" system) review. The last two of the four "in-scope" systems were selected by random drawing at a public meeting held on July 18,1997 by the Connecticut Nuclear Energy Advisory Council. The results of the ICAVP review process are made public via the protocol established with the ICAVP contractor and plan approval; and therefore will not routinely be documented in the Millstone Special Projects Office combined inspection report U3.1 Operations U3 01- Conduct of Operations 01.1 Loss of Soent Fuel Pool Coolina Event Followuo Insocction Scone (71707. 92901)

On June 25,1997, cooling water flow to the spent fuel pool was inadvertently stopped when the component cooling water and service water systems supporting the in service

, ("A" train) spent fuel pool cooling heat exchanger were taken out of service as part of.

%^' ' planned outage maintenance activities. With the cessation of forced cooling, the spent fuel

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pool water temperature increased approximately 10"F over the following 28 hours3.240741e-4 days 0.00778 hours 4.62963e-5 weeks 1.0654e-5 months . Based upon the higher pool temperature reading, observed by a plant equipment operator (PEO)

during routine operations shift rounds, the abnormal equipment lineup was recognized and spent fuel pool cooling (SFPC) was restored using the in service components of the-redundant "B" SFPC train. During event followup subsequent.to the recovery from the

" abnormal spent fuel pool heatup/the NRC inspector reviewed the licenseo's root cause-investigation process and independent review team (IRT) interim (draf t) report. The inspector attended an IRT working meeting and discussed findings and facts with both unit

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line management and nuclear oversight personnel. The inspector also reviewed the

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operating procedure for the spent fuel pool cooling and purification system, Observations and Findinas

' 1 Routine NRC resident inspection of the control room on June 25,1997 identified a spent l fuel pool temperature of less than 90'F. The normal operating procedure directs routine ,

1 operation of the SFPC system to maintain pool temperature below 125'F. Since a slight I j rise in temperature is anticipated with a train swap, the spent fuel pool temperature increase that occurred during the remainder of the day and swing shifts on June 25 would !

not have been expected to be recognized as an abnormal condition by the plant operator A review of the logs for the Mode 5/6 Daily and Shif tly Control Room Rounds for the period in question noted that the mid shift on June 26 documented a spent fuel pool temperature l

of 90*F on both control board temperature indicators, SFC*Tl27A&B. Since the {

i documented acceptance criteria for a temperature less than 125'F was met, only operator 1 cognizance of a rising temperature trend would have identified the loss of spent fuel pool cooling before it was identified by the PEO on radwaste rounds on the morning of June 26.

. Control room operator recognition of such a rising trend was impeded by the practice that a new log sheet is issued daily for all three shifts, commencing on the mid-shift. Therefore,-

, the mid shift operator did not have the benefit of a visual ald indicating to him when he

, filled out the Control Room Rounds sheet for June 26 that the temperature had risen to i 90'F from the mid 80's temperature indications documented on the previous day's log

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sheet.

The inspector reviewed the Control Room Rounds logs, the computer generated spent fuel

pool temperature plots, the alarm response procedures, the SFPC operating procedure (OP

3305, Revision 15), and examined the control board temperature indicators, discussing

with operators on shift both the conduct of shift log-keeping 6nd the degree of accuracy to

which temperature indications would be recordad. The inspector noted that SFC*Tl27A&B were marked in 5'F increments, which by common instrumentation and control convention would limit the degree of accuracy for any temperature readings to step intervals of I

approximately 2.5 degrees each. The inspector confirmed that the main control board

. alarm for spent fuel pool temperature annunciates at greater than 135'F. It was noted that i

the operators appropriately used the emergency operating procedure, EOP 3505A, for i * Loss of Spent Fuel Pool Cooling" to restore an operable cooling flow path once it was

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recognized that the system was not correctly aligned. The maximum temperature to which the spent fuel pool rose during this event was approximately 98'F.

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- The Unit 3 line management initiated an Event Review Team (ERT) to investigate the root

? cause and contributing factors to this event. The Nuclear Oversight organization also chartered an independent Review Team (IRT) at the request of senior station management to assess the event, its causes, and the conduct of the ERT. The inspector reviewed the completed ERT Root Cause investigation, monitored the IRT conduct of a meeting to

- ' discuss preliminary results of their review, and examined a copy of the IRTinterim repor <

it was determined that the interim nature of the IRT analysis, findings, and conclusions was i based upon the intent to perform a follow up assessment of the larger programmatic aspects of the " Conduct of Operations" at Millstone Station. Both the ERT report and IRT

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.,-:,,m,m- -v re-, , -~ ,,n,-um----,, , --e- --,,,:r- -- ,~we w, - w.-w , -, -,,,,w,ve,-- . , , - - - ,

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-Interim report documented several corrective action recommendations on specific (e.g., log keeping) and generic (e.g., configuration control issues) measures that could be

implemented to prevent problem recurrence and enhance future process controls, including-S - 7 those affecting human performance issues. While some of these corrective actions are directed toward longer term (e'.g., corrective action effectiveness, conduct of operations standards) enhancements, most recommendations appear that they should be implemented prior to the restart of the unit, Conclusions The Unit 3 spent fuel poolis designed from a structural standpoint to withstand a temperature of 200'F, has a design limit of 140'F from the standpoint of preservation of the purification components (e.g., resin), has an annunclator alarm setpoint of 135'F, and is controlled administratively to operate at a temperature of less than or equal to 125' Therefore, this event, involving the loss of SFPC for approximately 28 hours3.240741e-4 days 0.00778 hours 4.62963e-5 weeks 1.0654e-5 months and resulting in the heatup of the pool to approximately 98'F, was not significant from a safety related or design basis considerations. However, given the configuration management ramifications (i.e., the shut down risk impact with a cross train connected system lineup,

-the " train swap" control considerations, and the loss of continuity of operator cognizance of how safety related equipment was aligned), this event has significance not only with respect to the adequacy of current operational and configuration controls but also management's expectations for operational standards. -The former appears to have been addressed by the licensee's ERT report, while the latter is in the process of being assessed by the IRT oversight. Several corrective measures have been recommended and a programmatic review of the conduct of operations is planned as an IRT follow up activit The NRC will continue to monitor licensee progress in the assessment of this event, its generic implications upon the adequacy of other programs (e.g., corrective actions, conduct of operations), and the implementation of effective cortsctive measures. This overallissue will be tracked as an inspector followup item. (IFl 50-423/97 202 03)

U3 07 Quality Assurance in Operations 07.1 Qoerational Overslaht Activities (SIL ltems 73 & 86)

The inspector continued to routinely meet with Nuclear 0"ersight personnel to discuss activities and initiatives in the areas of the corrective action program enhancement, self assessments, priorities for unit restart readiness,10 CFR 50.54(f) involvement, and the a conduct of Nuclear Safety Assessment Board (NSAB) meetings. Where appropriate, .. - :

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' Nuclear Oversight surveillance, audit, and special reports were reviewed to assess the level of QA involvement in the performance of routine activities by the Unit 3 line management, as well as to determine progress in the corrective measures taken for known problem areas. Specifically during this inspection, the inspector reviewed the following documents and performance of assessment / evaluations, that provided evidence of continued .

management' attention to strengthening the Nuclear Oversight function at Millstone Statio e Dissemination of site briefing information on the conduct of an Independent Assessment of Nuclear Oversight by a review team of industry consultants and

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personnel from other nuclear utilities. This team performed a two-week, onsite assessment commencing on June 19,1997 and conducted a preliminary exit briefing with senior NU management before departing the station. This exit meeting was observed by an NRC Special Projects Office Branch Chie * lssuance of a self assessment report for the first quarter of 1997, documenting the Nuclear Oversight Performance Evaluation (PE) Department's strategic plan development and assessment of organizational effectiveness. Since the PE group was formed in December 1996, this self assessment evaluated the infrastructure and organizational effectiveness of the department using interviews, bench marking, and critical intelnal assessment * Documentation of a Nuclear Oversight Operational Readiness Assessment Plan for Unit 3. This document discusses the approach and process by which verification activities will be conducted to ensure safe operation of the unit, the effective j functioning of the line organizations, and the adequacy of preparations for the

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resumption of power operations after the extended shutdow * Publishing Northeast Utilities Nuclear Safety Standards and Expectations by the President and Chief Executive Officer of ue NU Nuclear Group. The principles discussed in this document appear directed to providing Nuclear Group personnel with management's focus on the safety of operations and other critical, mission-driven organizational requirement * Establishment of the Independent Review Team concept, including IRT staff ort,anization and resources, goals, and the use of processes in event evaluation The IRT process was utilized to furtt.er assess the loss of spent fuel pool cooling discussed in Section 01.1 of this inspection repor e issuance of a significant number of condition reports (CRs), along with appropriate use of its stop work authority, by the Nuclear Oversight Organization during this report period. An increasing level of Nuclear Oversight involvement in both problem identification and recommendations for improvement is evident not only in the CR but elso in audit and surveillance reports, as well as routine and special management meeting participation, in addition to review of the above program initiatives and assessment activities, the inspector specifically evaluated Nuclear Oversight and senior licensee management actions to address concerns with personnel overtime controls. The inspector noted that some overtime program violations had been recurring at Unit 3 since early 1996, The Nuclear Safety Engineering Group conducted an evaluation of the overtime controls at Millstone Station to determine if changes to Nuclear Group Procedure, NGP 1.09, " Overtime Controls for All Personnel at Millstone Station," were necessary. Based upon this review and issuance of a Level 1 CR to collectively address the identified overtime violations, the licensee determined that a revision to NGP 1.09 was required. On July 23,1997, the station operations review committee (SORC) approved revision 8 to NGP 1,09 and the new overtime control provisions became effective on July 25,199 .

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The inspector questioned when an updated Millstone Unit 3 Operational Readiness Plan (ORP) would be issued, since the existing revision 3 had been issued in Novernber 1996 and appeared to be outdated. The inspector noted that the NSAB had also commented at a board meeting conducted in May 1997 about the " obsolete" nature of the current ORP. It was recognized by the NRC that since November 1996, an interim " Recovery Plan" has <

been published; however, the protracted length of time since the last ORP revision l encompassed a number of management changes and corresponding adjustments to the i plan. On July 24,1997, a new Unit 3 ORP (revision 4) was issued, bringing up to date the current licensee philosophy on the rer. tart issues management and restart elements recognized to prepare Unit 3 for operational readiness and subsequent startup and power ascension activitie Overall, the Nuclear Oversight organization appeared to be actively involved in quality assurance and assessment activities directed toward effective corrective actions for identified problem areas and program enhancements to improve future operations. The initiatives noted above attest to a more active role by Nuclear Oversight in deal;r.g with line performance. However, while the routine QA and oversight reports document cognizance of the areas which represent the most significant challenges to improving performance, the ability of Nuclear Oversight to effect positive changes has not yet been fully demonstrate While examples of success, as noted above, do exist, significant challenges were noted by the NRC to remain in such areas as corrective action effectiveness, training enhancements, and plant configuration management controls, as are discussed in technical details in other sections of this report. Progress in the areas of QA/ Oversight program improvement will continue to be tracked by the NRC as part of SIL ltem 73, while needed training program enhancements, discussed further in Section M4.1 of this inspection report, will be reviewed as part of SIL ltem 8 U3 08 Miscellaneous Operations issues (92700)

08.1 Technical Snerification (TS) Noncomolianca Insoection Sqnna Several recently issued licensee event reports (LERs) have dealt with TS noncompliance issues. The inspector reviewed the LERs for root cause and safety significance determinations and adequacy of corrective actions. The inspector also verified that the reporting requirements of 10CFR 50.73 had been me Observations and Findinos (Closed) LER 50-423/96-34

, This LER documented that the residual heat removal (RHR) pump suction relief valves were

not set in accordance with TS 3.4.9.3. The TS required the RHR reliefs be set at 450 psig

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in order to provide over pressure protection when the reactor coolant system cold leg temperature was less than 350*F. The actuallift pressure for the RHR suctien reliefs is 440 psig. The lif t pressure for the valves, as documented in the original design change and

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the subsequent set point calculation, is 440 psig. A TS change request was processed and submitted to the NRC for review to change the value to between 426.8 and 453.2 psi The inspector verified the licensee had entered the applicable TS action statement and had not credited the RHR suction reliefs as a means to satisfy TS 3.4.9.3. In addition, the licensee had issued proposed technical specification change request (PTSCR) 314 96 to change the RHR suction relief setpoint. This request was approved on July 10,199 (Closed) LER 50-423/97-14 This LER documents that both trains of the control room envelope pressurization system I

(CREPS) were inoperable due to instrument air valves 3 IAS V644/V725 being found out of position. These valves supply air to solenoid operated valves which coritrol air operated I dampers in the control building. The solenoids are not qualified as category 1 equipment and therefore, it must be postulated that they fall in the most adverse position. This (

creates the potential for a breach of the control room envelope which would render the CREPS inoperab!e. The air valves had been opened to allow purging of the cable spreading room and apparently had not been closed af ter completion of the evolutio The licensee promptly restored the air valves to their required position and revised the procedure to correct the deficiencies. The inspector verified that procedure OP 3314F was revised to restore the valves to their normally closed posith IClosed) LER 50-423/97 23

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This LER documents that the main steam isolation valves had not been tested in accordance with the literal requirements contained in the TS. The Technical specifications require that the valves bo demonstrated operable by verifying iull closure within 10 seconds in modes 1,2, and 3 when tested pursuant to TS 4.0.5. Relief from the requirement to perform a full stroke test during power operation had been granted by the NRC in the licensee's inservice test program; however, the licensee had not submitted a TS change request to delete this requirement from TS. The inspector verified the licensee had initiated a PTSCR to eliminate the requirement for full stroke testing the MSIVs in modes 1 and IClosed) LER 50-423/97 24 This LER documents that the engineered safeguards building noble gas activity monitor (3HVO'RE49) was inoperable and that best efforts to repair the monitor had not been initiated in accordance with TS 3.3.3.10. The radiation monitor was declared inoperable since it was incapable of measuring an effluent concentration as low as 1.0 E 06 uCl/c The instrument had been purged by operations personnel due to the receipt of spurious alarms, The radiation monitor design contains a feature where, upon completion of a purge, a new background level is automatically measured and entered into the circuitr Review of the database entries indicated that a background value of 1.01 E-06 uCi/cc.was entered. Background readings at this location are normally 1.0 E-08 to 1.0 E-07 uCi/c The high background level was attributed to electromagnetic interference from welding

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activities in the general area. The incorrect background level prevented the monitor from meeting the sensitivity requirements specified in the TS bases, interim corrective actions included revising operations procedure OP 3250.62 to enter a -

zero background level reading af ter purging the radiation monitor, and chemistry procedure SP 3867 to verify zero background af ter completion of surveillance activities. Long term corrective actions include a review to evaluate the removal of the automatic background subtraction feature associated with 3HVQ'RE49 and other radiation monitor l

The inspector verif:.sd that procedural changes had been made to the operations and chemistry procedures to zero the background level after purging and completion of the surveillance in addition, an engineering work request was initiated to delete the automatic background subtraction feature from applicable radiation monitors, j (Closed) LER 50-423/97-26

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This LER document 5 that ASME Section XI required examinations on some service water supports had not been re-performed during the subsequent refueling outape, for supports that initially failed inservice inspection (ISI) examinations during 1989. The licensee had originally assumed that the supports were located in areas where performance of the examinations was impractical.10CFR 50.55a orovides for relief, when justified. However, relief was not specifically requested to allow excluding the examination of these component supports. The f ailure to perform these examinations is a condition prohibited by TS 4.0.5. Subsequent inspections by the licensee revealed that the supports were acceptabl As corrective action, the licensee revised the ISI program documents to include ASME Section XI requirements for performing additional and successive examinations, and included guidance for requesting relief in accordance with 10CFR 50.55a. The inspector verified that the ISI Program Manual was revised to capture these requirement Conclusions The LERs discuss conditions prohibited by TS. Further NRC review of each LER established that while the licensee's operational activities were proper evolutions, literal compliance with the plant TS had not been maintained. Based on the above corrective actions and the low safety significance of the issues, these licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policy. The listed LERs are close However, the closure of the LERs does not address the generic concern for TS complianc A review of LERs issued as of April 1996 revealed that there have been a number of LERs that have dealt with TS compliance problems relating to questionable interpretations. This area is of current interest for further NRC review and is included as an NRC followup activity; documented as Significant items List (SIL) Item 7 _

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U3.ll MaintenanGR U3 M1 Conduct of Malntenance M1.1 General Comments The inspectors determined that the maintenance and surveillance activities observed were properly performe M1.2 Inserv!ce Test Pro 2 ram Review Insoection Scooe (73756. Tl 25151_1Q1 The inspectors evaluated the effectiveness of Northeast Nuclear Energy Company's (NNECO) inservice test program for safety-related pumps and valves at Millstc,ne Unit 3.

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The inspectors focused primarily on components in the auxiliary feedwater (AFW),

intermediate head safety injection (IHSI), and reactor plant component cooling water

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systems. Thece risk significant systems are needed to prevent or to mitigate the dominant l core damage frequency events identified in the Millstone Unit 3 Individual Plant Examinatio The purposes of inservice testing (IST) are to assess the operational readiness of pumps and valves, to detect degradation that might affect component operability, and to mainta'n safety margins with provisions for increased surveillance and corrective action. The requirements for IST are contained in Millstone Unit 3, TS 4.0.5, which requires testing in accordance with 10 CFR 50.55a, " Codes and Standards," and Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code). The inspectors reviewed administrative and surveillance procedures, engineering evaluations and calculations, test results, and LER's germane to the Millstone Unit 3 IST progra Observations and Findinas Millstone 3 Unit is implementing the first 10-year interval of the IST program, which is based on Section XI of the Code (1983 Edition). However, pursuant to 10 CFR 50.55alf)(4)(iv), NNECO is currently upgrading its program for the second 10-year interval to the 1989 Code Edition which includes ASME/ ANSI OMa 1988, " Inservice Testing of Pumps and Valves in Light Water Reactor Power Plants," Part 6 (OM-6) for pumps, Part 10 (OM 10) of ASME/ ANSI OMa 1988 for valves, and ASME/ ANSI OM 1,1987 for pressure relief dnvice M1.3 IST Proaram Scooe Insoection Scoce The inspector used NNEC0's IST program submittals, the Updated Final Safety Analysis Report (UFSAR) and technical specifications, design basis documents, system drawings,

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.and surveillance procedures to verify that the pumps and valves in the selected systems i

that perform a safety function were included in the IST program.

4 Observations andFindings During an IST program review conducted in June 1996 as part of their response to a 10-CFR 50.54f letter, the licensee identified 75 valves that were not included in the program, and 45 instances involving valves in which all the safety functicns were not tested periodically. Components in thirteen safety related systems were involved, including the reactor coolant safety injection, service water, containment recirculation spray, and emergency diesel generator systems. The licensee reported the condition to the NRC in Licensee Event Reports 50-423/96 21 and 50 423/96 24. The inspector conducted a detailed review of the selected systems to confirm that the licensee had changed the program scopa to include all of the required components and tests. The inspector found that with the exception of residual heat removal pump seal cooler relief valves 3CCP*RV239A/B and residual heat removal heat exchanger relief valves 3CCP*RV64A/B,

- the revised IST program satisfied the scope statements of Article IWV 1100, and Section 1.1 of OM 10 and OM The licensee determined that the program scope discrepancies had been due to lack of

- management commitment to the program, and inadequate program monitoring and self-assessment. Corrective _ actions included staff augmentation, development and implementation of detailed administrative procedures and project instructions, and compilation of a component level design basis document detailing the bases for decisions regarding program scope and test requirements. In the document, the safety functions of each component are traced back to the TS, UFSAR, and design documents and

- calculations. The design-basis scope document is not required by the Code and was a good licensee initiative. The inspector also noted that a new project instruction for periodic IST program self assessments was included in the new program. The inspector found that the licensee's corrective actions addressed the root causes of the program deficiencie Resolution of specific test discrepancies were being tracked under Action Request 96036464. Twenty nine major items encompassing 143 action items were being tracke The inspector reviewed approximately half of the major items covering 112 components and tests. Most of the action items involving surveillance procedure and test schedule revisions were completed. However, due to the operating condition of the plant, few tests had been performed at the time of the inspection. The inspector determined that no test =

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failures had yet occurred, and that the outstanding tests were being tracked adequatel * The licensee has committed to update LER 96 21 w!th the results of the new test ' Conclusions The IST program scope problems constituted a violation of 10 CFR 50.55a(f), which-

- requires inservice testing of ASME Code Class components as defined in Article IWV 1100:

and Section 1.1 of OM 10 and OM 1. The causes for the program failures were being addressed adequately, and individual test discrapancies were being tracked and resolved

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appropriately. Therefore, this licanaee identified and corrected violation will not be cite,d since the criteria of Section Vll.B.1 of the NRC Enforcement Policy wera ma M1.4 (Undate) Sll item 53 ARCOR Contino insoection Scone (62707)

The licensee developed special procedure SPROC 97 3 4, "Special Inspection and Testing l of Service Water Piping Previously Lined with ARCOR Epoxy," to verify the quality of the

ARCOR coating applied to the internal surface of the service water (SW) piping. This

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testing was being performed to establish baseline adhesion values for the ARCOR coating,'

and to determine the condition of the existing ARCOR coatin0 within the SW system. The inspector witnessed portions of the testing on the ARCOR test plates and inspection of selected SW spool pieces, Observations and Findinas The test pi'ogram to establish the baseline adhesion value for ARCOR coatings consisted of

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performing pull tests to f ailure of the various ARCOR test plates. The plates were f abricated with proper intercoat, heated intercoat, contaminated intercoat, and a releasing agent intercoat. Testing revealed that the ARCOR coating could withstand a force of 2000 psiif the ARCOR coatings were properly appiled; whereas contaminated surfaces could only withstand a force of approximately 500 psi before the ARCOR coating delaminate Based on these bounding valuce, the licensee performed pull tests (a non-destructive test method) on the ARCOR coated spool pieces installed in the field.to 1000 psi to ,

demonstrate that the ARCOR coatings were properly applied. Each ARCOR coated spool '

piece was tested at each end and at the approximate mid point of the spool at the 90 180, 270, and 360 radial degree location Testing of the *B" train SW revealed no ARCOR delamination from the pull testing to 1000 psi. However, during the removal of one of the pull tabs, a small place of the ARCOR top coat delaminated. The licensee was subsequently able to remove an area of approximately one square foot from this area indicating tht.t it was not properly bonded. Condition Report (CR) M3 971729 was written to document this condition. A couple of days later, another coating failure occurred during the removal of a pull tab for a spool that had recently been coate *

Investigation into the failure for the newly applied ARCOR coating revealed that the cure ,

itime had been exceeded.- In addition, one of the environmental conditions (humidity)L h specified in maintenance procedure MP 3710C,'" Application of Linings to Plant Systems 3 Subject to Salt Water immersion," was not maintained. A review of maintenance records -

of other recently coated spool pieces revealed that the cure time had been exceeded for five other SW spools. A voluntary stop work was initiated on all Unit 3 SW coating application due to these application error The SW spool pieces identified as having application errors were re-tested by "X CUT" (a destructive test method) to determine the quality of the ARCOR coating. Nn additional

. _ .

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) *,

7

) *

- proble:ns were noted. As a result of the failures of,the ARCOR coating during removal of

, the pall tabs, the licensee concluded that they could not demonstrate that the ARCOR

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" - coating on the SW spools tested by the pull test methodology had been properly applied.,,

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All but one ARCOR coated spools in the *B" train of SW have since been tested by " : CUT;" no other defamination f ailures occurred.

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The licensee concluded that the root cause for the suspected improper application of the ARCOR coating vvas procedure non-compliance. The procedure for application was not idmM c written due to incorrect assumptions made by the painters and contractor -

laspectore. The ARCOR re-coat window time was incorrectly assumed to be seven hours or thumb ne!!icheck for ability to cause indentat icn in product indication not fully cured).

The environmental condition control was recognized as being lost, however the craft reestablished the conditions and continued the coating applicaticn without obtaining any further guidanc The inspector reviewed procedure MP 3710C and the maintenance records for ARCOR c ating application and noted that severalindividuals har' not followed the procedur lavestigation revealed that the SW spools in question al! exceeded the 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months maxirnum

- overcoat tir ; by 45 minutes to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and 41 minutes. Procedure step 4.5.2 states that the re-mat window is determined from the product specific technique sheet (PSTSh The -

PSTS maximum acceptable overcoat condition is 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months or thumb nail test with no indentation, whichever is less. The collective procedural noncompliance indicates both an individual and departmental control performance problem. The failure to follow procedures constitutes a violation of technical specification 6.8.1. (VIO 50 42397 202 04) ConcluslDna A review of ARCOR coating application work orders revealed that on six separate occasions the recoat window was exceeded. These examples demonstrate a low standard for f6l lowing procedures and a lack of management oversight for this critical evolutio The condition of existing ARCOR coating within the SW system and the potential effect of ARCOR delamination on safety-related componente is under NRC review an is included as an Independent Corrective Action Verification Program followup activity; this is docun ented as Significant items List (SIL) Item 6 M1.5 Service Water Class lil Pinino Retest Insoection Scoce (62707)

The inspector reviewed maintenance activity M3 9618746, replacement of service water (SW) piping to ventilation unit 3HVQ' ACU2A, to ensure that proper retest requirements were specifie :

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33 Observations and Findings The work activity consisted of the replacement of the SW ventilation piping; a 1 1/2 inch nominal pipe size (NPS), ASME Code Class ill pipe. A review of the work order and ASME'

Section XI repair and replacement plan revealed that the licensee had invoked the use of code case N 4161, " Alternative Pressure Test Requirements for Weld Repairs or Installation of Replacement item by Welding, Class 1,2,3,Section XI, Decision 1." The work activity required only a visual examination (VT 2) of the affected mechanical joints at normal operating pressure and temperatur Code case N 4161 specifies that a system leak test,in lieu of a hydrostatic pressure test, may be performed provided that a non-destructive examination (NDE) is performed in accordance with Section XI with a VT ASME Section XI requires that after welding repalts on the pressure retaining boundary of Class lil piping, either a hydrostatic test or non destructive testing be performed. In a memorandum, dated January 13,1995, the NRC approved the use of code case N-4161 for Unit 3 as an alternative to the provisions of ASME Code Section XI, thus eliminating the requirement to perform a hydrostatic pressure test. The NRC authorized the use of this code case provided that additional surface examinations were performed on the root (pass) .

layer of butt and socket welds on the pressure retaining boundary of Class 3 components when the surface examination method is used in accordance with Section lli of the ASME Cod NU memorandum, CES 95163, dated 2/16/95 attempted to clarify the guidance provided by the NRC. The guidance ind;cated that a suriace examination would be required on Class 3 piping when Section XI required surface examinations of the welds.Section XI Section ND 5222 states that a surf ace examination is not required on two inch NPS or less. The welds in question were for piping of 1 1/2 inche The inspector discussed with the licensee the interpretation of the use of the code case provision. The licensee stated that their interpretation was based on discussions with the NRC in 1995. The inspector contacted NRR for clarification of this issue to determine what was the intent of the 1995 lotter. The NRC reviewed this issue and concluded that a system leak check was adequate for Class lli NPS two inches or less. The NRC staff did not intend that the licensee apply additional surface examination of the root pass to weld joints two inch NPS and smaller as a condition for approval of the code case, Conclusion Code case N-4161 was approved for use at Unit 3 by the NRC in a letter dated January 18,1995. The licensee's interpretation and use of the code case for Class ill piping was proper. The retest specified for work activity M3 9618746 was adequat i

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U3 M3 Maintenance Procedures and Documentation M3.1 Testina of Safetv/ Relief Valves Insoection C,coce The IST program invoked the requirements of ANSI /ASME PTC 25.3, Safety and Relief Valves / Performance Test Codes, for testing safety / relief valves. As permitted by 10 CFR 50.55a(f)(4)(iv), however, the licensee's procedures also referenced Operation and Maintenance (OM) 1 1987. The inspector reviewed licensee and vendor procedures against the scope, test methodology, and corrective action requirements contained in these documents, Qbservations and Findinas The licensee categorized pressurizer power operated relief valves (PORVs) 3RCS"PCV455A and 3RCS*PCV456 as Category B/C valves in their IST program, and tested the valves in accordance with TS 4.4.4.1, Relief Valves,4.4.9.3.1, Overpressure Protection System, and Section 7.3.1.2 of OM 1. The tests involved determination of operability of pressure sensing and valve actuation equipment, and verification of the operation and electrical characteristics of the valve position indicators. Calibration of the PORV actuation instrument channels was performed once per refueling interval, and the PORVs were operated through one complete cycle of full travel with the blocking valves open while the plant was in hot standby or hot shutdow NRC Information Notice 89-32, Surveillance Testing of Low Temperat1re Overpressure Protection (LTOP) Systems, documented that some licensees did not 'ranslate the PORV stroke times assumed in their LTOP analyses into IST surveillance recairements. Licensee calculation NM-027 ALL, Active Valve Response Times, assigned a FORV open stroke time limit of two seconds based on safety grade cold shutdown system '.equirements. However, the licensee's cold overpressure mitigation (COM) system analysi', assumed a more restrictive stroke time limit. Westinghouse memorandum NSD ',AE-ESI-97167, da:ed March 19,1997, specified an opening requirement of 0.85 sr.:onds. Surveillance procedure SP 36018.2, Reactor Coolant System Vent Path Operability Check, specified an acceptance criterion of one second. The inspector verified that the acceptance criterion satisfied Section IWV 3413(b) of the Code, which requires PORV stroke times of ten seconds or less to be measured to the nearest second. The licensee will need to update calculation NM 027-ALL to reflect the more restrictive criterio The inspector reviewed procedure SP 3712A, Pressurizer Code Safety Valve Surveillance Testing, and Wyle Laboratories Report No. 44656-0, Recertification Test Program For Millstone Nuclear Plant, Unit 3, dated June 4,1995. The acceptance criteria for "as-found" and "as-left" set pressure tests were plus or minus 3 percent and plus or minus 1 percent, respectively. The criteria conformed to TS 3.4.4.2 requirements and met or exceeded the requirements of the Code. The inspector noted that step 2.1.2(b) of l procedure SP 3712A specified a five minute waiting period between consecutive valve lif ts l instead of the minimum 10 minute period required by Section 8.1.1.8 of OM 1. The

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licensee provided an NRC approved relief request for the deviation. The licensee's

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surveillance procedure and the vendor tests conformed with the req'irements u of PTC 2 and OM The licenses tests the main s aam safety valves in place using a hydraulic lif t assist (hydroset) device per procedure SP 3712G, Main Steam Code Safety Valve Surveillance l Testing. This method is sanctioned in PTC 25.3 and OM 1. A sample of main steam safety valves also were tested at Wyle Laboratories in 1997. The inspector reviewed test l results and Wyle Laboratories Procedure No.1071, Testing of Dresser Spring Operated Main Steam Safety Relief Valves, and found that the requirements of TS 3.7.1.1 and OM 1 were met. The licensee properly evaluated system operability when "as found" tests failea to meet the specified acceptance criteri Step 4.1.16 of procedure SP 3712G specifies that hydroset pressure be increased until the safety valve begins to simmer. A preceding note cautions that the valves not be allowed l to " pop". The licensee noted that Section 2.7 of PTC 25.3 defines " simmer" as an audible or visible escape of fluid at an inlet static pressure below the popping pressure and at no measurable capacity. Thus, if the actual difference between the valve's simmer point and set pressure were great enough (e.g. greater than one percent of set pressure), the current test method would be nonconservative. The licensee initiated condition report M2 97-0955/M3 971758 to evaluate the condition. The inspector did not consider it likely that the difference would have a significant effect on valve performance during a rapid overpressure transient. However, the issue was relevant to literal compliance with the Code, and had potentially generic consequences regarding the validity of the test metho The licensee's observation evidenced a good questioning attitude towards safety and Code compliance, inspection followup item (IFl 50-A*3/97 202-05) is opened to review the results of the licensee's evaluation of this matte Other Code Class 2 and 3 relief valves were tested periodically in accordance with maintenance procedure MP 3762WD, Setting and Testing Relief Valves. The inspector reviewed the procedure and found that it satisfied the requirements of OM 1 overall. The proceaure stated that no set pressure corrections for ambient temperature were needed when normal system operating temperature was less than 250 degrees Fahrenheit ("F),

while the set pressure setting was to be increased by three percent where system operating temperature was between 250"F and 1000"F. Section 8.1.3.5 of OM 1 requires the ambient temperature of a relief valve's operating environment to be simulated during the set pressure test. If the effect of ambient temperature on set pressure can be established for a particular valve type, then the valve may be pressure tested using an 4 *

ambient temperature different from the operating ambient temperature. Correlations; ;

between the operating and testing ambient temperatures must be established by test per -

Sections 8.3.2 and 8.3.3 of OM-1. The ASME has found that some relief valve manufacturers have no engineering or test bases for the correlations that they provide, and

- has established a task force to determine standardized criteria for the correlations. The

- licensee ultimately will need to establish a technical basis for its set pressure adjustment to be in full compliance with OM-1. However, since the difference between the " cold" ( bench test) and operating set pressures typically is small, the inspector concluded that the'

licensee's approach was not an immediate safety concer _

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l 36 Conclusions

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Pressurizer safety / relief valves and main steam safety valves were tested in accordance .

i

'-v . with Code requirements. However, a followup item was opened regarding the potential:

' that relief valve testing to the valve " simmer" point may be nonconservative. For other '

Code Class 2 and 3 relief valves, set pressure adjustments made to account for differences

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in bench test and normal operating ambient temperatures need to be justified by test per OM- M3.2 Pumn Testino ' Insoection Scone

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The inspectors reviewed surveillance procedures and performance records against OM 6 i requirements for test periodicity, quantities measured, and allowable ranges. The review I included pumps in the auxiliary feedwater, intermediate and low pressure safety injection, ;

and reactor plant component cooling water systems, Observations and Findinas Procedure EN 31121, IST Pump Operational Readiness Evaluation, contained the . ,

acceptance criteria for the safety related pumps at Millstone 3. The inspector verified that the hydraulic and vibration criteria established by the licensee conformed to the limits in i Table 3 of OM 6. The licensee's vibration monitoring program exceeded Code requirements by including the pump drivers, which are explicitly excluded from the program scope in Section 1.2(a) of OM 6. The procedure also contained guidance pertaining to the required corrective actions if a pump entered the alert or required action ranges. A note preceding step 4.4.4 of the procedure stated that new reference values could be established as corrective action for a pump that was operating in the alert range. This guidance was inconsistent with Sections 4.3 and 4.5 of OM-6, which state, respectively, that reference values shall only be established when a pump is known to be operating acceptably, and that additional reference values may be established only if IST of the existing set of reference values is acceptable. The licensee agreed with the inspector's observation and initiated a procedure change to delete the note from the procedure. The inspector noted that the provision had not been invoked for any pumps at Millstone The inspector noted that the charging and intermediate head safety injection pump

performance curves contained in Attachment 4 of procedure EN 31121 differed from the. .

( -

- curves (Figures 6.3-4 and 6.3 5, respectively) in the UFSAR. - The licensee explained,that : <

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the UFSAR figures were based on system flow calculations used in the accident analyses,

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1 while the curves in the engineering procedures were actual pump performance curves

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developed during pre-service testing. -The inspector had no further questions regarding the Curve For IST of pumps, Section 5.2 of OM 6 requires that the resistance of the system shall be:

varied until either the flow rate or (differential) pressure equals the reference value. Where system resistance cannot be varied, flow rate and pressure shall be determined and

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-.. 1- i , c , - n,,,,. , -- -

, .-.-.-m -,

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compared to their respective reference values. Clarification provided in Section 5.3 of, NUREG 1482 states that the Code does not. allow for variance from a fixed reference 4 value. In order to ensure that periodic tests are performed under repeatable conditions, the

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NRC.has determined that a tolerance of +/ 2 percent (%) of the reference value may be '

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used without NRC approval. For a tolerance greater than +/- 2%, compensatory adjustments may be made to the acceptance criteria, or an evaluation may be performedi justifying the greater tolerance. Where resistance cannot be varied,it is acceptable to use the broader criteria in Table 3b of OM 6 as the tolerance, Most of the safety-related pumps at Millstone 3 are tested through fixed resistance L

minimum flow lines that are capable of, but were not designed for, adjusting the flow rates.

, The licensee identified that for the charging, intermediate head safety injection, and

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feedwater pumps it could not meet the tolerance band prescribed in the NUREG due to large instrument fluctuations, in pump specific evaluations, the licensee justified reference value ranges of up to 7.2%/+ 10% of the reference values based on the minimum flow lines being fixed resistance flow paths. Also, since the reference values were close to the minimum flow rates required for pump protection, the licensee determined that throttling to attain a tighter tolerance band would be impruden The inspector agreed that throttling the minimum flow rate may be undesirable. However, it did not appear that the licensee had considered fully the options to reduce the instrument fluctuations discussed in Section 4.6.1.5 of OM-6, including use of symmetrical damping devices, instrument line snubbers, or throttling small gage valves in the instrument line The inspector concluded that since it was possible to adjust the flow rates through the minimum flow lines, although undesirable, the licensee needed to request NRC relief to use the broader tolerance bands for these pump The inspector also found that the licensee had changed the IST procedure for the emergency diesel generator fuel oil transfer pumps to no longer adjust pump discharge flow to attain the required tolerance. The change was made to reduce operator burden and to avoid having to declare the diesel generators inoperable during IST. As discussed in GL 87-09, Sections 3,0 and 4.0 Of The Standard Technical Specifications On The Applicability Of Limiting Conditions For Operation and Surveillance Requirements, and Section 3.1.2 of NUREG 1482, entry into a TS limiting condition for operation is not itself adequate justification for deviating from Code requirements. The licensee will need to provide additional justification for using a broader reference value tolerance in a relief request to the NRC, or take other actions to meet the tolerance band required by the Code. The licensee agreed to evaluate means to reduce the instrument fluctuations, or to request relief from-the Code requirement, Conclusions Acceptence criteria established for IST of safety-related pumps met or exceeded Code requirements. Equipment or procedure changes will be needed to meet Code requirements for repeatability of test reference values, or NRC relief to use broader tolerance bands will1 be neede ]

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M3.3 Valve Testina Insoection Scoce The inspector reviewed surveillance procedures, methods, and acceptance criteria for several types of valves in the IST program. In addition, the inspectors reviewed the licensee's treatment of reactor coolant system pressure isolation valves, Observations and Findinas Power Ocerated Valve Exercise Testa Articles IWV 3413(a) and Section 4.2.1.4(a) of OM 10 require limiting values of full stroke time to be established. The inspector reviewed surveillance procedure acceptance criteria for power operated valve stroke times against calculation NM 027 ALL, Active Valve Response Times: Technical R(.quirements Manual 3TRM 3.6.3, Containment Isolation Valves; and UFSAR Tabte 6.2-65, Containment isolation Valves and verified that the limiting values selected by the licensee were appropriate. Where not specified in accident analyses or other design / licensing basis documents, limiting values were assigned based on a multiple of the reference value stroke time and the physical characteristics of the valv The licensee's method in those cases was technically justified and satisfied the Code requirement. The inspector noted a discrepancy involving charging pump safety injection isolation valves 3SlH'MV8801 A/B in which the close stroke time limits in the TRM and the UFSAR table differed. The licensee also had identified the error and was processing a change to the UFSAR to correct the conditio The licensee established stroke time reference values based on the average of three stroke times taken when the valves were known to be in good condition. This method was consistent with industry practice and Section 3.3 of OM-10. _The IST program was in transition from Section XI of the 1983 Code Edition to OM 10. The inspector verified that the reduction in the stroke time limit for electric motor-operated valves with stroke times greater than 10 seconds was being implemented in the surveillance procedure The inspector noted during review of procedure SP 3608.G, Safety injection System Valve Operability Test, that the licensee exercised and timed both the open and closed strokes of many valves that had safety functions in only one direction. This practice exceeded Code-requirements and provided additionalinformation for performance trending of power-operated valve The stroke time tests of motor-operated valves 3SlH'MV8801 A/B were performed using a1 motor power monitoring diagnostic system that is installed temporarily at the remote motor control centers. This method differs from the customary IST practice of using remote valve position indicating lights, and provides additional information regarding valve performanc Stroke time was defined in the procedure as the period between, maximum motor inrush :

current and torque switch trip. The inspector noted that the method could result in longer ,

stroke times than those derived from valve position indication lamps that are actuated by

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limit switches. However, this f actor likely is offset by the elimination of the operator response time lag inherent in using a stop watc *

A:ticle IWV 3300 and Section 4.1 of OM 10 require remote valve position indicators to be _ l verified by local observation of valves at least once every two years, in Section 4.2.6 of NUREG 1482, the NRC clarified that the requirement applies only to remote indicators that ,

are used in exercising and stroke timing power operated valves. The inspector considered ,

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that the requirement applied to the motor power monitor as well, and noted that the surveillance procedure provided for the verificatio !

. Check Valve Testina Check valves in the selected systems were categorized properly in the licensee's program as Category A or AlC valves. Full flow testing of check valves was performed where practical under verified accident flow conoitions contained in the TS, UFSAR, or other design documents, as specified in Position 1 of Generic Letter 89-04, Guidance On Developing Acceptable Inservice Test Programs. Quarterly partial flow tests were followee up during cold shutdowns or refueling outages with full flow tests, disassembly and inspection, or nonintrusive techniques. For disassembly and inspection, the licensee followed the guidance contained in Position 2 of GL 89 04 for grouping and corrective action. The licensee's methods for verifying check valve closure on cessation of flow met the requirements of Article IWV 3522(a) for verification by positive mean Procedure SP 3608.6, Refuel Full Stroke Testing of SlH Header Check Valves, was utilized to exercise the intermediate head safety injection system injection header check valve The procedure measured flow only in the main headers vice through the individual branch lines. Thus, flow rate through the branch line check valves was not verified, and nonintrusive test techniques.were used to verify valve obturator position. The inspector reviewed procedures SA 97718, Acoustic and Magnetic Non-Intrusive Check Valve Analysis, SA 95923, Non-Intrusive Check Valve Testing Data Collection, and data traces recorded during the performance of procedure SP 3608.6 in May 1995. The traces clearly showed the check valves hitting their backstops, and seating after cessation of flo As discussed in Section 4.1.2 of NUREG 1482, the NRC has determined that use of nonintrusive techniques is acceptable as another " positive means" of verifying that check valves are full stroke exercised within the meaning of the Code. To substantiate the validity of the method, the licensee must address and document the items enumerated in Position 1 of GL 89-04 in its IST program, including: (1) The impracticality of performing a full flow test; (2) A description and summary of the alternative technique used; (3) A description of the method and results of the program used to qualify the method to Code-requirements; (4) A description of the basis used to verify that the baseline data has been generated when the valve is known to be in good working order; and, (5) A description of tho basis for the acceptance criteria for the alternate method, and the corrective action to be taken if the acceptance criteria are not met. While the licensee's procedures and the "

quality of the data supported their use of nonintrusive test methods, the licensee will need to address explicitly the items listed in Position 1 of GL 89-04 in their IST program document. The inspector noted that the licensee also identified this issue during their

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1996 review of the Millstone 3 IST program, tracked in Condition Report item 9603646405, and initiated action to complete the required item Reactor Coolant Pressure Isolation Valve Testino The operational and functional requirements of the pressure isolation valves at Millstone 3 are contained in TS 3.4.6.2.f. The TS imposes maximum leakage rates on the check valves located between the reactor coolant system and contiguous low pressure systems in order to ensure that the leakage rates will not exceed the pressure relief capacity.of the -

- relief valves. Overpressurization and rupture of the low pressure systems would result in a loss of coolant accident outside of the primary containmen The pressure isolation valves were classified properly in the IST program as Category A/C valves, and leakage rates were tested at least once every refueling interval in accordance with procedure SP 3601F.4, Reactor Coolant System Pressure Isolation Test, and results were trended in accordance with Article IWV 3427(b) of the Code. For applied pressure less than the maximum functional differential pressure (2250 +/- 20 psla), the measured leakage rate was adjusted by the square root of the ratio between the maximum functional differential pressure and the test differential pressure. This method comported with the requirement of Article IWV 3423(e). The inspector found a minor discrepancy _in the licensee's calculation in that test pressures measured in pounds per square inch gage were not corrected to absolute pressure. Since the error resulted in slightly overestimating valve leakage rates, no adverse safety consequences ensue Manual Valves The Code requires IST of Cate0ory B manual valves that fall within the scope of 10 CFR 50.55a. TP0 inspector noted that there were very few manual valves included in the

~

Millstone 3 IST program. For example, chemical addition isolation valves 3CCP'V303,

'V304, 'V349, and 'V350 that provide safety class boundary isolation for the reactor plant component cooling water system were not included in the program or exercised periodically in accordance with Article IWV-3412 or Section 4.2.1 of OM 10. Per operating procedure CP-38071, the normally shut valves are opened and left unattended for approximately 30 minutes when adding chemicals to the system. The licensee explained the exclusion by citing Section 2.4.2 of NUREG 1482, which states that valves need not

, be considered " active" (requiring periodic exerciso testing) if they are only temporarily l removed from their safety positions for a short period of time under administrative controls.

l The inspector agreed _with the licensee's position regarding these valves. However, the

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L -

Llicensee will need to include these, and similar valves, in its IST program as " passive"

! Category B valves, as applicable.

. Conclusions

Power-operated valve exercise tests met or exceeded Code requirements, and the licensee's use of the motor power monitor diagnostic system was commendabl Nonintrusive testing of check valves also was noteworthy, but more documentation was needed to meet GL 89 04 requirements. Additional manual valves may need to be added

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to the IST program, even if their safety functions are only passive. Pressure isolation valves were leakage rate tested in accordance with the Millstone Unit 3 TS and the Cod U3 M4 Maintenance Staff Knowledge and Performance M4.1 (Ocen) eel 245/974 02-06. 336/97-202-06.423/97-202-06: Ineffective Maintenance and Technical Trainino Proaram Evaluation Insoection Scone (41500)

The programs reviewed were non-licensed operator; electrical maintenance personnel; mechanical maintenance personnel; instrument and control technician; chemistry technician; radiation protection techr.ician; and engineering support personne CFR 50.120 requires that training programs be established, implemented, and maintained using a systems approach to training (SAT) as defined in 10 CFR 55.4 A SAT-based program requires 1) Systematic analysis of the jobs to be performed, 2) Learning objectives derived from the analysis which describe desired performance after training, 3)

Training design and implementation based on the learning objectives, 4) Evaluation of 1 trainee mastery of the objectives during training, and 5) Evaluation and revishn of the training based on the performance of trained personnelin the job setting.

l The inspectors evaluated 18 of 25 characteristics of a SAT as described in NUREG-1220.

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The evaluation involved assessing the SAT characteristics related to systematic analysis of training requirements, training program design and implementation, trainee evaluation, and training program evaluation. Unless specifically noted otherwise, the results obtained apply -

to each of the training prograros reviewe Observations and Findinos An assessment of the programs and processes related to the systematic analysis of the jobs to be performed mdicated the tasks were selected for continuing training based primarily on the workers' and supervisors' desires to expand their knowledge into new technical areas. Although appropriate for increasing the level of technical knowledge, this method would not ensure that on-the-job performance was maintained at the level needed to support safe day-to-day plant operations. Changes to equipment and procedures were assessed by the licensee to determine their impact on training. Personnel interviewed felt that changes identified from these assessments were incorporated into training. However, reorganization of workers and changes in their responsibilities when transferring from the

- Connecticut Yankee site were not assessed to ensure that personnel had the appropriate Millstone site-specific knowledge. Overall, the systematic analysis of the jobs to be performed was functioning adequately but with weaknesse Interview results suggested that workers felt the training they had received was of good quality. The inspectors observed of fective interaction between students and instructor, and good use of visual aids and job aids during classroom training sessions. The lesson materials were of good quality and the trainees indicated that the instructor presentations x v -___J

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42 were generally good. However, many of the plant personnel interviewed indicated that

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instructors needed to spend more time in the plant to improve their credibility by obtainingi

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.fi rst-hand knowledge of the uses of the training they were providing. Overall, training F design and implementation was functioning wel Information gathered in interviews suggested that the evaluation of trainees during training had weaknesses. Non-licensed operators noted that the examinations they were given were not a good assessment of the information they received in training and, n at leas one case, were given several months after completion of the training. Additionally,

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I methods used to remediate non-licensed operators, primarily self study of the le'sson plans,=

were not sufficient to prevent repeat failures, in all reviewed programs, the task selection process and training methods used in continuing training do not ensure maintenance of task proficiency. The use of 'significant notices', while timely, does not require any evaluation to determine the extent to which the information was understood by the workers or to ensure that newly hired workers will receive the information as part of their initial trainin Interview results also indicated that most people believe the on the-job training and evaluation (OJT/E) programs should be changed due to known weaknesses. Those interviewed indicated that the OJT/E process was not formal enough and is not high on the list of management priorities. - Additionally, the lack of management emphasis on OJT/E has resulted in workers not being fully knowledgeable about the status of their own qualifications, in the maintenance and technical training programs some task qualifications do not expire and others require periodic renewal, i.e., renewal every year, every two years, or every five years. However, those tasks that require periodic renewal do not always require that task proficiency be demonstrated but rather use the opinion of the supervisor as the basis for continued qualification / renewal y f qualification without

' consideration of individual task assessment. The weaknesses in the implementation of the OJT/E process is offset, at least in part, by the apparent willingness of workers to ask for assistance in task performance or to inform their supervisor if they feel unable to perform a task even if they are fully qualified to perform the task. Overall, the evaluation of trainee l mastery of objectives during training was inadequat The task qualification matrix for engineering support personnelis the notable exception

- related to task qualification status. Extensive revisions to the engineering qualification standards has been undertaken to ensure that qualifications are consistent across all engineering disciplines. The update to the matrix is viewed as positive by engineers and their supervisors.

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s in the area of program evaluation, interview results indicated that although trainee critiques of training'are encouraged and are collected they are not being used to identify potential:

deficiencies in the training program. There is also no program to gather job incumbent performance data related to degraded task abilities, on-the-job experiences, and input from supervisors regarding perform e. e-based training need The licensee has a number of curriculum advisory committees (CACs) that are specifically -

designed to provide site-wide oversight of each of the technical training program However, interview results indicated that the site-wide perspective is frequently lost by

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, holding one-on-one meetings between a training representative and a plant superviso l' A Their discussions, although focused on unit specific issues, may have unexplored site wide s ,

' implications that are not being addressed as part of the program effectiveness evaluation.-

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T ,The' notable exception is the health physics technical advisory counsel (TAC). The TAC is -

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comprised of technician representatives from each unit that meet regularly with the specific task of discussing task proficiency issues, in general, technical training program evaluation was found to function inadequatel The significance of the training program deficiencies identified by the inspectors were L( . evaluated against the problems previously identified in the Nuclear Training Department

" Top Ten" List. The " Top Ten" list was developed as part of a corrective action plan addressing recent problems in the operator training program. However, the inspectors found that implementing the appropriate corrective actions for each of the eleven items on the list would not prevent recurrence of the those specific problems nor prevent similar problems from developing in other training areas because none of the items specifically addressed the SAT process weaknesses underiving each of the issue Although the inspection focused on, Unit 3 training programs, the SAT processes are common to all units at the site. Therefore, the problems are considered also applicable to Units 1 and 2. The failure to maintain training programs derived from a systems approach I to training, as described in 10 CFR 55.4 was evidenced by the failure to evaluate trainee mastery and conduct effective training program evaluation and is considered an apparent violation of 10 CFR 50.120. (eel 50-245/97 202-06; 50 336/97-202-06; 50-423/97 202-06), Conclusion:

The overall implementation of the systematic approach to training (SAT) for the technical training programs at the Millstone site was generally inadequate to ensure continued qualification of technical and non-licensed personnel to successfully perform in-plant wor As described above, one violation was identified concerning a failure to properly evaluate trainee mastery of tasks and conduct training program effectiveness evaluation U3 M8 Miscellaneous Maintenance issues M8.1 (Closed) Unresolved item 50-423/96-08-18: Adequacy of the IST Program

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(The results of the licensee's assessment of the Millstone Unit 3 IST program, the corrective ^ ~: actions planned and implemented, and NRC findings are discussed in Sections U3.M1 ~andi U3.M3 of this inspection report. An additional NRC concern documented by this item involved the licensee's failure to perform timely operability determinations for the components for which IST had not been performed. To correct this condition, the licensee revised the IST program manual to require a condition report to be initiated if a component is determined to be within the scope of the Code. The condition report will require that an operability determination be performed. The inspector concluded that the licensee's corrective actions addressed the IST program deficiencie . .

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i ' Additionally, the inspector reviewed the licensee's disposition and corrective action for CR e

M3 97-0866 which documented the identification of valves inappropriately left out of ,the z IST program. - Programmatic corrective measures, already in progress, appeared to be adequately directed to the resolution of the documented concern M8.2 (Closed) LER 50-423/96-50:

. This LER documented that the range of control building chilled water pump suction *

pressure gages used for surveillance were not in accordance with ASME Section XI requirements. On December 11,1996, the licensee identified that the control building -

chilled water pump suction pressure gages did not meet the requirement of Section 5.4.1.2(a) of OM-6 that the full scale range of each analog instrument shall not exceed three times the reference value. The licensee concluded that pump operability was not impaired since the gages' full scale range only exceeded the Code requirement by 4 psig, but otherwise met Code accuracy requirements. The inspector agreed with the licensee's assessment. The licensee substituted the gages with process computer points that met the range and accuracy requirements of the Code for digitalinstrument The licensee performed a review of other instruments used for IST and documented the results in memorandum CBM 97-114, dated March 24,1997. Gages and computer points utilized during testing of pumps in seven other systems, including component cooling water, auxiliary feedwater, intermediate head safety injection, quench spray, and recirculation spray, also were found not to conform to OM-6 requirements. As corrective action, the licensee changed procedures to use substitute gages, changed the calibrated ranges of the computer points, replaced instruments, and/or revised pump reference flow rates. At the time of the inspection, many of the substitutions and recalibrations had been

- performed, and a design change request to implement other corrective actions had been-developed and was being reviewe The licensee determined that the condition was caused by the informality of the IST program and lack of provisions for periodic assessment of program compliance with the Code. To prevent recurrence, a comprehensive administrative program document was written and approved. The guidance contained in the program document comported with Code requirements, and the new program contained provisions for periodic program assessment The inspector found that the condition would not reasonably have been expected to have

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been prevented by corrective actions for previous violations or findings, and.the licensee's

"" s corrective actions and actions to prevent recurrence were comprehensive and acceptabl This licensee-identified and corrected violation of the instrument range requirements of.OM-6 is being treated as a Non-Cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Polic M8.3 (Closed) LER 50-423/97-22:

This LER documented that testing of the control room emergency air filtration system had not been performed after routine filter replacement in violation of technical specification

)

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(TS) surveillance requirement 4.7.7(f). Two historical instances were identified, one in i

each train. Each filter train was subsequently tested satisfactorily during normal

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surveillance testing. The licensee attributed these events to a lack of a prompting mechanism within the applicable maintenance procedures or work orders. Missed TS surveil lances were previously cited as a violation at Unit 3. As part of the corrective actions for that violation, the licensee will review surveillance procedures to ensure prompts exist for conditional surveillances. The corrective action is scheduled to be completed by September 30,199 The inspector reviewed the work orders and maintenance procedures and noted that they had incorporated the TS surveillance requirement. Additional corrective actions are being performed as part of the previously cited violation. Based on tiie above corrective actions and the low safety significance of the issues, this licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. This LER is close M8.4 (Closed) ACR M3 96-0159 (Partial SIL ltem 15) insoection Scooe (92902)

The inspector reviewed the corrective actions taken by the licensee to resolve the issue documented in ACR M3-96-0159, the associated purchase order and design calculations

- for the needed replacement component, and the component design drawings, Observations and Findinns Letdown heat exchanger 3CHS*E2 had exhibited leakage at the lower flange for a long period of time. The leaking fluid caused corrosion of the carbon steel flange bolts and represented a constant source of contamination. The licensee considered corrective actions to address the leak as early as 1989, as documented in Nonconformance Report (NCR) 389-239 (dated 7/12/89). However, due to unexpected difficulties, alternate correction approaches and changing circumstances, the final resolution was still pending in 1996. The proposed corrective action, at that time, was replacement of 21 of the 28 flange bolts with corrosion resistant stainless steel bolts. The design adequacy of the bolted joint, using only 21 bolts, was based on the use of the new bolts' certified material tensile properties, inspector review of this proposed corrective action concluded that the design represented an apparent conflict with ASME code requirements.

1 The licensee documented this discrepancy in Adverse Condition Report (ACR) M3-96-015 The corrective actions to resolve the ACR include replacement of the heat exchanger and .

the training of design engineers on code requirement The licensee had an available heat exchanger that was essentially identical to the original leaking unit. To improve the leak tightness integrity and performance characteristics of this replacement, the unit was returned to the original manufacturer, Holtec International, for modification, code qualification and testing. The inspector reviewed the vendor prepared design drawings and code qualification calculations and the licensee's vendor surveillance

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records for the replacement unit. It was noted that the licensee will provide the necessary - ,

- documentation to satisfy the ASME Code Data Report and the ASME= Code Reconciliation '

cduring the close out of maintenance modification (MMOD) M3 97512, after successful-

-acceptance testing at operating temperature and pressure. It was also noted that the' -

"Holtec drawings listed the flange bolt torque as 250 ft-Ibs instead of the 350 f t-lbs found to be necessary to achieve leak tightness during the hydro test. Following the document - ;

review, the heat exchanger was inspected in the field by the inspector, and it was verified

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that a refurbishment plate was installed and correctly stated the new shell design pressure of 165 psi The inspector discussed the purchase and installation effort with the responsible licensee project engineer. The engineer provided documents to show that the paperwork to achieve ASME Code compliance was in place and confirmed that a design change notice (DCN) to revise the flange torque values to 350 f t-lbs on the component drawing had been issue To assess the corrective action regarding training, the inspector reviewed the lesson plan and interviewed several engineers who had received the training. Most of the interviewed engineers were responsible for stress computations and had a clear understanding of the issue and correct design procedures for bolting. The lesson plan was concis Conclusions Replacement of the 3CHS*E2 heat exchanger resolved the flange leakage problem. With a new, larger sealing gasket, it could be a permanent solution. Interviews with design engineers confirmed their understanding of ASME Code requirements for flange boltin The inspector concluded that the licensee's corrective actions were appropriate and ACR M3 96-0159 is considered closed. The NRC will review, as inspector follow-up item (IFl 50-423/97 202-07), the results of the heat exchanger performance tests and the associated completion of documentation to show ASME Code compliance when the plant achieves normal operating temperature and pressur '

M8,5 (Closed) ACR M3-96-0563 (Partial SIL ltem 33) insoection Scoce (92902)

The inspector reviewed the corrective actions taken by the licensee to resolve the issue documented in ACR M3-96-0563 regarding the access manholes to the Normal and Reserve Station Service Transformer fire protection water valve pits, Observation and Findinas Manholes provide access to the Normal and Reserve Station Service Transformer fire protection water valve pits. Several Adverse Condition Reports (ACR's) were issued to request relief from the inspection and surveillance burdens associated with making access to the pits.- When the access manholes are covered, the pit air spaces must be sampled before entry. When the manholes are left open, only a daily sampling is required but the -

openings present a fall hazard which must be protected against. To accommodate frequent

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access, the manholes had been left open and temporary guards had been installe . However, due to their temporary nature, the guards required constant surveillance. -The

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deficiency of the temporary guard and the burden of frequent sampling was noted in several ACR's. To resolve this concern, permanent protective guard rails were installed at the two manholes. They were designed to meet OSHA strength and dimensional requirements and to accommodate ready acces An inspection of the Normal and Reserve Station Service Transformer fire protection water valve pit access manholes was made by the inspector. Stainless steel railings, bolted to _

the concrete pads and walls, with drop chains at the entry points, were installed at each manhole. The inspector discussed the ACRs with their originator who was satisfied that the railings resolved his concern. When queried why there were multiplc ACRs for the same issue, he stated that there were some initial misunderstandings of his concer ; Conclusions The permanent railings at the Normal and Reserve Station Service Transformer fire protection water valve pit a(. cess manholes appeared structurally sound and met OSHA dimensional and design requirements. The inspector concluded they were an appropriate resolution of the reported concern. Based on their installation, ACR M3-96-0563 is considered close U3.111 Enoineerina U3 E2 Engineering Support of Facilities and Equipment E (Undate - SIL ltem 57) ACR M3-96-OO80: Inadeouate Separation Between Redundant Electrical Circuits: and ACR M3 96-OO81: Potential Electrical Seoaration Violations with Solid State Protection Svstem Insoection Scoce (92903)

ACR M3-96-0080 identified potential noncompliances with electrical separation requirements for the reactor trip switch on Main Control Room (MCR) Board MB4 (MCB-MB4), and the safety injection switches on MCB-MB2 and MCB-MB4. These conditions have existed since unit startup in 1985. A root cause of the electrical separation noncompliances was identified as inadequate job skills for maintaining electrical separation during maintenance and modification ACR M3-96-0081 identified potential electrical separation violations associated with electrical wire bundles for the two trains of the Solid State Protection System (SSPS). The power cable supplying power to the opposite SSPS trains was less than one inch from the internal backplane wiring in the logic cabinet The inspector reviewed the licensee's corrective actions to address the above concern l

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C 48 Observations and Findinas c

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Following the discovery of the noncompliance with electrical separation requirements for; s redundant protection equipment trains on June 10,1996, the licensee staff performed -

additional system walkdowns to search for discrepancies in electrical separations of: (i)

installed wiring in other MCR Panel Boards, and (ii) electric cables on cable trays in various -

' plant areas. - These additional inspections identified numerous electrical separation

, noncompliances on various MCR panel boards and electrical cable installations in general plant and protected areas. (Reference LERs 96-015-01 and 96-015-02). The licensee's ; <

corrective actions were: (i) modifications to install electrical separation barriers.and "re-

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train" cables as necessary, i.e., redundant cable trains tie-wrapped to minimum separation distances, (ii) develop training module on electrical separation and implement continuing training for applicable personnel, and (iii) revise applicable work planning process procedures to incorporate guidance for electrical separation inspection plan developmen Separation barriers made of QA 18 gauge galvanized sheet metal have been installed on the inside of the MCR panel boards MB4 and VP1 to correct the discrepant condition Based on field walkdowns of the MCR panel boards, the inspector verified that the installed barriers were in compliance with Reg. Guide 1.75 and IEEE Std. 384-1974 requirement The barriers were found to be securely mounted on the panel boards with no air gaps observed. The Control Building isolation pushbutton (PB1-3HVC CB1) located on 3HVS*PNLVP1 has been returned to service after successful functional retest results per surveillance procedure SP 3614 On the insides of several MCR panel boards identified on the Unit 3 electrical separation discreriency list, electrical wire bundles have been tie-wrapped to maintain acceptable separation distances. The licensee's OC inspection results for AWO M3-97 03509 indicated that the completed re-training of electrical wire bundles on the internal MCR panelboards, MB1 to MB6 and VP1, met the acceptance criteria for electrical separatio Based on field walkdown of the affected MCR panel boards, the inspector did not find any operability concern LER 96-015-02 (an update of LER 96-015-00 and LER 96-015-01) identified electrical separation noncompliances in specific areas of the MCR panel boards. Interviews with the licensee staff indicated that work is in progress to correct the identified noncompliance The inspector also conducted field walkdowns in other plant areas, e.g., cable spreading -

room, diesel generator room "A", and electrical switchgear room "A", to assess whether

cable arrangements are in compliance with separation requirements. The inspector did not

- : find any new noncompliances.which were not identified by the licensee's electrical separation inspection program. LER 96-049 01 has identified 976 deviations of minimum

- separation distances between a Class 1E and a non-Class 1E cable in the cable spreading:

and instrument rack rooms. The licensee indicated that about 160 noncompliance items have been corrected through re-training of the cables, and repair of Sil-temp protective wraps,- Another 540 noncompliance items are related to inadequate separate distances between cable trays. The licensee is in the process of issuing DCNs for the installation of -

cable wraps to meet the regulatory requirements. However, the proposed modifications are not fully implemented yet. Since the work on correcting electrical separation

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noncompliances is ongoing and expected to be completed prior to plant startup, this issue will remain open.

l One corrective action for ACRs M3-96-0080 and M3 96-0081 is the adequate training of

, applicable personnelin the Engineering Department and General Technical Services who are l responsible for maintaining electrical separation requirements. A training program on-electrical separation requirements was developed. Classroom training on separation criteria

, for electrical wiring in electrical panels and cabinets, and for cables and raceways in general plant areas and cable spreading areas were provided to applicable personnel from November,1996 through April,1997. The inspector found that the training course i

contents (in ES-CONT-C098) adequately identified the regulatory requirements and " thumb rules' for electrical separation to the students. However, minor comments on the exact definitions of technical terms (e.g., common cause initiating events) were provided to tha licensee training staff to enhance the training course materials. The licensee agreed to incorporate these comments in the classroom training material The Millstone Station Procedures U3 WC1, " Unit 3 Work Management," and U3 WP2,

" Unit 3 Work Planning," have been revised to include guidance for development of electrical separation inspection plans when electrical maintenance on safety-related or non-safety related cables, conduits, or raceways are required. These procedural revisions were effective as of June 1,1997, Conclusions The licensee has developed a training program on electrical separation requirements, and classroom training has been provided to applicable personnel in the Engineering Department and General Technical Services. The licensee has also completed revisions to work planning procedures to include guidance for development of electrical separation inspection plans. However, work on correcting electrical separation noncompliances ;n the MCR panel boards and other plant areas are ongoing to meet the plant startup deadline. For example, installation of separation barriers in other MCR panel boards have not been complete Since corrective activities are ongoing, this issue will remain ope U3 E3 Engineering Procedures and Documentation E Site level MEPL Proaram Review The overall site material, equipment, and parts lists (MEPL) program was reviewed; comments and discussion that apply to all three units are provided her ~ '

The inspector reviewed the following MEPL-related documents:

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NGP 6.01 Material, Equipment, and Parts Lists for in-Service Nuclear Generation Facilities, Rev. 9, 8/13/9 .

NGP 6.05 Processing and Control of Purchased Material, Equipment, Parts, and Services, Rev. .,

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Specification SP-ST-ME 944, Lists for in Service Nuclear Generation Facilities (MEPL Program), Rev. O,7/12/95 through Rev. 4, 4/26/9 !

e t-Production Maintenance Management System (PMMS) Training Manua .

PMMS User's Guide Volumes 1 & .

Pl.29, Development of Millstone Unit 3 Design Bases Summary Documents, Rev.1, l Effective date 3/11/9 .

Northeast Utilities Quality Assurance Program (NUQAP) Topical Report, Appendix A, l Rev.18, 8/15/9 '

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Engineering Self Assessment of the Material, Equipment, and Parts List (MEPL)

Program, Millstone Unit No. 3, ESAR-PES-97-009,4/12,9 . Selected MEPL evaluations, and MEPL related ACRs and CR .

NGP 6.10, Use of the PMMS ID-System and BOM Database, Rev. ' At the time of the initial MEPL Program difficulties (discussed under MEPL Program status),

the controlling document was NGP 6.01. This has subsequently been replaced by the improved Specification 944. Specification 944 has also undergone improvements and revision over the last two years. The new Specification provides detailed guidance for the MEPL process in Figures 7.3 and 7.4, which are used to document the evaluations and subsequent reviews. The Spec addresses both component level MEPL evaluations and parts Bill of Materials (BOM) MEPLs. Section 5 provides instructions on the safety classification process, in particular: determination of the licensing basis and the safety function at the plant, system,-component, and part level, it covers safety related, augmented quality, and non-safety-related determinations. Figures 7.3 and 7.4 provide for a safety evaluation and USO determination for changes in classification. The licensee has also established added controls over any changes to the system where the parts ,

classification information resides (namely, NGP 6.10 to control the PMMS System).

The MEPL program is now receiving significant resources and attention at the site level and in Units 2 and 3. Unit 1 efforts will begin in earnest when the work on Unit 3 is completed. Four issues were identified with respect to the site level program, as follows:

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- There continues _to be a historical question of the potential to have non-safety-

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related (NSR) parts installed in safety-related (SR) components. This has been documented on a number of ACRs and CRs for each unit. The plans to address thi '!

concern for U3 appear comprehensive (but are not fully implemented yet). For U1 and U2, the plans are currently less comprehensive and implementation is not as far along. The licensee has not yet fully justified the plans for Units 2 & . Specification 944 does not check for the impact on NUQAP, Appendix A when downgrading a component from SR to NSR. Any changes to the NUQAP that-

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reduce commitments (e.g., the list of SR items) require prior NRC approval per 10 ;

CFR 50.54(a).

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- 3. - NRC previously (Inspection Reports 95-07 and 95-09) raised a concern that the

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MEPL procedures did not adequately consider normal operations and anticipated operational occurrences (AOOs) as part of the " design basis events" to be

considered when making safety-related classifications under the MEPL progra Discussions with NU managers responsible for the MEPL program stated that the intent of the current program, under Spec. 944, is that engineers performing MEPL evaluations must consider normal operations and AOOs as part of the " design basis events" in making safety-related classifications. Step 5.2.2.4 of Spec. 944 states l

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that guidance can be found in EPRI NP-6895. Page 4-2 of NP-6895 contains a definition of Design Basis Events that includes normal operations and AOOs, as well as other items. This indirectly addresses the concern, however personnel performing evaluations will not usually have or reference the EPRI documen . The PMMS database is not complete. Some SR components are not in the i database,_e.g., snubbers. Many augmented QA and NSR parts and components are also not in the database. The impact on site programs of these gaps in the

[ database needs to be evaluated.

E3.2 (Undate - Partial SIL ltem 25) ACR M3-96-0912: Acoarent Violations and Escalated

. Enforcement items from NRC Insoection Reoort 96-201. Items No. 18.19. & 43

, This ACR addresses three apparent violations from NRC inspection report 96 201. These items are also under consideration for escalated enforcement action, which has not been completed yet. The items relate to the MEPL program, which is reviewed in this section of j- the report.- Issues associated with the MEPL program are identified herein. The licensee is still actively working on MEPL evaluations that must be completed before startup. Also,

.- there are other areas of inspection review on the program that will be performed over the next reporting period. SIL ltem 25 remains open.

E3.3 Unit 3 MEPL Status Uodate

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Unit 3 has'approximately 60,000 components in the PMMS database, of which about 19K are safety-related (SR) and 3,000 are augmented quality (due to fire protection, radwaste, station blackout, or ATWS commitments). During the Performance Enhancement Program (PEP) reviews a number of componen'ts were originally identified for downgrade, however J

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- this action was stopped in Unit 3 befue being implemented as a result of lessons learnedt

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. - on Units 1 and 2. Over the 1995 and 1996 time frame Unit 3 performed system level MEPL evaluations of all systems and hence all components in the database. As a _ result of;

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these efforts a number of changes in component classification were implemented, and are generally summarized here:

-e About 3,000 duplicate items were identified and removed from the databas e About 2,000 items were downgraded from augmented quality to NSR.

e About 1,000 items were upgraded from NSR to augmented quality.

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e About a dozen items were upgraded from NSR to SR, but did not require phvsical changes to the component e About another dozen items were identified where NSR components had to be upgraded to SR, but these items required design modifications to change out equipment. These modifications are stillin progres * About 2,000 to 3,000 items were downgraded from SR to NSR. These items v!ere all either database errors o downgrades of items that had been classified as SR due to utility convenience rather than regulatory requirements, lhe above activities were all at the component level. For each component, the MEPL program also evaluates the parts of the components and establishes the classification for each part on the Bill of Materials (BOM). In early 1937, Unit 3 performed an operability determination (OD No: MP-010 97) that satisfactorily evaluated all safe-shutdown, SR components with one or more NSR parts in their BOM. This included an engineering evaluation, " Acceptability of installed Parts / Material Associated with Active Components Credited for Defense in Depth." In 1996 and 1997 Unit 3 began MEPL BOM evaluations for all SR components that have ever had any work performed on them. As part of this effort, whenever NSR or Undetermined (U) parts are reclassified to SR, a full work history examination is being performed to ensure acceptable quality of parts installed the component E3.4 Unit 3 MEPL Pronram imolementation (Uodate-Partial Sll item 25]

The inspector selected a system MEPL evaluation (for the CVCS System) and a few individual component MEPLs for review to determine if classification determinations were reasonable and properly documented. The MEPLs were compared with drawings, FSAR descriptions, and components in the plant. Additionally, a number of components and component identification were noted in the plant and compared to the MEPL and PMMS systems to ensure that the components wero properly classified and were properly entered into PMMS. The parts issuance portion of the program was not reviewed due to ongoing issues identified by the licensee in that are The inspector noted the following five issues, which will be tracked with S!L item 25, In order to properly classify an item in the MEPL Program, the safety function must be clearly understood. The latest revision of Spec. 944 requires this to be determined and documented in the MEPL evaluation. The earlier versions of the Spec. also recognized the importance of determination of safety function, but were not as speci'ic in the procedure. The MEPL evaluations reviewed did not always clearly document all of the safety functions. Examples include: the overall CVCS System, the CVCS function with respect to the Reactor Coolant Pump seals, and valves CHS*V503, *V505, 'V436, 'V437, AND 'V30 . The MEPL evaluations reviewed did not list all of the pertinent design documents and FSAR references on the MEPL determination, Figures 7.3 or 7.4 (example, identify CVCS System MEPL).

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53 The numbering scheme for PMMS results in differences between the identity for components in the field and in the PMMS database when the number of characters'

exceeds 15, FSAR Figure 3.2.2 states that an asterisk (*) indicates that equipment is quality assurance category 1 (i.e., SR). However, the inspector noted that not all SR components use the * as noted in the FSAR, e.g., SR snubbers; thore is some ambiguity in the use of the * for relays; and some identification tags and signs in plant do not use the *, even though the component is SR and the * is used in PMM . While performing the MEPL-related plant tours, the inspector noted that some orange or A Train components are being newly painted purple (the color of the B train), e.g., OSS pump and AFW pump. This creates an increased potential for

" wrong train" type of human error E3.5 (Uodate) Unresolved item 50-423/95-07-10: Containment Hatch - Downaradina SR eouinment throuch the MEPL oroaram Through the early 1990s, NU had a program to review, and where possible, downgrade components from safety related to non safety related. This item addressed the issue of improper downgrades. The generic or programmatic aspects of the downgrades are being addressed under the Eels and SIL 25 noted herein. One particular component identified with this unresolved item was the containment personnel hatch and its interlocking syste MEPL Evaluation No, MP-CD-132 downgraded a number of parts associated with the containment hatch. As a result of concerns raised, the licensee re-evaluated the pressure retaining parts of the hatch and raised their classification from NSR to SR. This action then required a design change (PDCR MP-95-025) that was implemented to upgrade these parts to SR. There are currently 231 parts on the hatch BOM. Over the last two years, a number of MEPL evaluations have been performed on the containment hatch parts. One particular aspect in question was whether the hatch interlock mechanism served a SR function. The MEPLs determined that it did not; and, the inspector verified this by a review of the design drawings and discussions with the port'nent engineers. During this review '

the inspector noted the following isst as: The most recent MEPL (CD-789) for the hatch did not clearly specify which of the previous MEPLs had been superseded and thus it was not clear which of the multiple MEPLs were still effectiv . The PMMS system incorrectly notes that CD-789 is the pertinent MEPL for all containment hatch BOM parts in PMM . The acceptance criteria (on Maint. Form 3712X-1, Rev. 2) for the Technical Specification surveillarce test do not accurately verify that the hatch interlocks function properly. However, the steps and the note within the procedure itself (SP 3712X, Rev. 5) do properly test tia interlock l o

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This unresolved item remains open pending resolution of the above noted issue E3.6 RHR Svstem Control Valves As an example of a SR component with associated NSR parts and components, the inspector selected the residual heat removal (RHR) system flow control valves for the RHR heat _ exchanger (HX),3RHS*HCV606 &607 (HX outlet valves), and 3RHS*FCV618 & 619 (HX bypass valves)i These valves were identified in ACR 13427 on 5/15/96, as having a design problem whereby their failure position on !oss of control air would give maximum --

cooling. This is appropriate for the RHR system but could cause an over-temperature condition in the reactor plant component cooling water system (CCP). This resulted in a design change (EWR M3 96097, DCN No. DM3-S-0662-96, DCR M3 96065) and a new MEPL evaluation MP3-CD-0947. This design change makes several modifications, including: limiting the full open position of the HX outlet valves, failing open the RHR HX bypass valves on loss of air, and adding a SR solenoid valve between the valve positioners and the actuators to ensure a vent path to place the control valves in their safety position when required. The inspector reviewed the associated documentation and observed the

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modification work in progress in the plant. The MEPL evaluation appropriately classified !

the various items in accordance with the new desig During the review of these valves, the broador question of SR/NSR interactions (particularly as it concerns interactions between control grade and SR components) was raised. The licensee presented an Engineering Report M3-ERP-97-OOO8, Rev. O, dated 6/19/97, titled

" Assessment of Safety Related Valves with Nonsafety Related Controls." This report analyzes 101 valves and associated controls in Unit 3. This is a comprehensive study which establishes design criteria and groups, analyzes each of the valves, and recommends changes where needed. In general the analysis of the control grade components assumes failure in the adverse direction if it may be in a harsh environment (such as post-LOCA or HELB). If in a mild environment, the analysis is performed for two cases, with the control grade components operating as designed and with them failed "as is." Random or spurious failures of these components may be an initiating event, but are not assumed to occur concurrent with a design basis accident. This position was verified to be consistent with NRC review positions noted in: the Standard Review Plan (SRP), NUREG-0800, Section 7.7; Resolution of USl A47, Generic letter 8919, and NUREG-1217; and issues surrounding information Notice-79-2 No unresolved issues were identified as part of this revie U3.E7 Quality Assurance in Engineering Activities E Review of items to be Comolgted After Restart insoection Scone (92903)

In a letter dated April 16,1997, the NRC superseded the " Demand for information" of earlier letters and requested that the licensee provide, in part, the following information pursuant to 10 CFR 50.54(f):

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For each unit, the list of significant items that are needed to be accomplished prior to restart;

For each unit, the list of items to be deferred until after restart; and,

For each unit, the process and rationale used to defer items until af ter restar The letter also requested updates approximately every 45 days for the first two items. On May 29,1997, the licensee provided the initial lists for Units 2 and 3 in response to this letter. On July 14,1997, the licensee provided the initiallists for Unit 1 and updates for Units 2 and The inspectors reviewed the information provided for Unit 3 to assess the content of the list and whether the deferrals were appropriate. Specifically, the inspectors reviewed a sample of deferred items to ensure issues that could affect equipment operability or the ability of equipment to perform its intended design basis function were not deferred. The inspectors also reviewed the licensee's process for identification of significant items for restart and items which could be deferred.

. Observations and Findings Significant item For Restart List To develop the significant items for restart list the licensee reviewed all adverse condition reports (ACRs) open as of January 1,1996, and all ACRs and condition reports (CRs)

initiated after that date. Significance level A or B ACRs and level 1 CRs were included as significant items. The lower significance level ACRs/Crs were screened further and those issues that questioned the operability or design basis function of maintenance rule group 1 or 2 systems were included as significant items. (Maintenance rule group 1 and 2 systems include safety relateo systems and risk significant systems.) The licensee noted that there are also many other non-significant items that are planned to be completed prior to plant restart. The inspectors concluded that the licensee significant items for restart list provided the information requested in paragraph 1 of the revised 10 CFR 50.54(f) letter dated April 16,199 Deferred items List The licensee provided the screening criteria used to defer items in their May 29,1997, response letter. Similar criteria are also provided in Project Instruction (PI) 20, " Unit 3 Startup Item Administrative Instructions," items screened to determine if they could be deferred included unresolved item reports (UIRs), non-significant ACRs and CRs, non-conformance reports (NCRs), engineering work requests (EWRs) and automated work orders (AWOs). An item was classified as startup required if it was necessary to accomplish one of the following actions:

Implement or support a change to plant technical specifications,

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L 56 I

e Correct a licensing or design basis deficiency, e- Accomplish a restart license commitment, e Resolve an operability concem assu.tated with a maintenance rule group 1 or 2 syste . If the item did not fit any of these categories it was considered for deferral, subject to i management concurrenc A total of approximately 1500 items were included on the deferred issues list at the time of the licensee's update on July 14,1997. The inspectors reviewed the one line description of all of these items and selected approximately 30% for additional review. In selecting the items for further review the inspectors considered those items in safety significant systems where the one line description indicated the potential for equipmot operability questions or other operational concerns. The inspectors reviewed supporting documentation for these items and discussed the issues with the licensee staff as necessary to obtain sufficient information on each of the items. The inspectors had the following findings:

e Open item reports (OIRs), which document potential testing deficiencies, were not included in the initial (May 29,1997) submittal of deferred items. However, wher questioned by the NRC, OIRs were included on the deferral list in the July 14,1997, updat *

The NRC's April 16,1997, !etter specifically requested that bypass jumpers and

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control room deficiencies be included in the deferred items list. The licensee did not originally review these items for inclusion in the list. : However, when questioned by -

- the NRC, the licensee reviewed these items and found that all but one of the bypass jumpers and control room deficiencies had been included as deferred issues as a result of another associated document, such as an EWR or AWO. The item that was not included was a recorder associated with a non-safety system and would not have affected safe operation, e The licensee's July 14,1997, update added items to the deferred list that existed well before the time the initial list was submitted, but these items were not included on either the original deferred list or the significant items for restart list, it was not evident to the inspectors or discussed in the update letter whether the initial screening addressed these items or if _they were initially screened as non-significant

- restart issue e .The inspectors identified twenty-two items on the deferred list that the licensee did not intend to defer. For ten of the items, the individual actions necessary to resolve the issue were scheduled for completion prior to estart, in nine cases all actions necessary to close the issue were already complete. The licensee reclassified three items that were questioned by tbc inspectors. Two items were AWOs to repair three emergency lights and were placed on the startup schedule because the affected lights were included in the 10 CFR Part 50, Appendix R program. The

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other item that was reclassified to' be required for startup was an EWR to replace a

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-i level recorder in the auxiliary feedwater syste o: . The inspectors fourid that the licensee _did not have a consistent "nethod for coding _

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, restart actions in the Action item Tracking and Trending System , AITTS). Some

. actions were coded to a schedule reference to clearly indicate th(t the action _was required to be completed prior to startup. Other items required bMore restart did not have a schedule reference entered and were tied to startup o fy by having the'

requested action completion date precede the expected startup dMe. The licensee

documented this concern on CR M3-97-226 In addition, the inspectors discussed with the licenseo the status of the corrective actions- *

, recommended in self assessments, independent third party reviews, nuc'. ear oversight

' reviews, and on site review organization reviews (ie, ACR 7007, Root Case Evaluation -

j- Effectiveness of the Oversight Organization,' Joint Utilities Management , Association report,

. etc.) and if any were to be_ deferred. The licensee stated that they are r.orrently reviewing

= all of these reports and will address what actions they have taken or wil be taking in their response to item (4) of the NRC's April 16,1997, letter. Specifically, . tem (4) requested

. the licensee to submit what actions they have taken to ensure that fu.bre operation of each

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unit will be conducted in accordance with the licensee, regulations, a td Final Safety

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Analysis Report (FSAR).

i T Conclusions p

d The inspectors found that the licensee's determination for which items could be deferred

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was generally appropriate. The three items that were removed from the deferred items list

. as a result of this inspection would not have had a significant impact on plant operations if l they had not been resolved prior to startup,

However, the inspectors concluded that the deficiencies discussed above constitute a violation of paragraph (a) of 10 CFR 50.9 which requires licensees to provide complete and I

accurate information. (VIO 50-423/97-202-08)

Also,in resolving CR M3 97 2265 the licensee should ensure adequate controls are in

_ place to ensure that actions required prior to startup do not get inadvertently deferred as a

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. result of changes to action due dates in AITTS. This is particularly important for those

'itemsLthat have some actions required for startup and other actions that may be deferred.

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p U3 E8 ; Miscellaneous Engineering lasues

E8.1 - Residua' l Heat Removal (RHR) Heat Exchanoer Bottino Susceotible to Boric Acid -

-- Attack (SIL ltem 47)

insoection Scoo1 (92903)

The inspector reviewed the licensee's adverse condition report (ACR) No. M3-96-0391 that

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? addresses the RHR heat exchanger bolting susceptibly to boric acid attack. (SIL ltem 47)

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58 Observations and Findinas During a 10 CFF 50.54(f) walkdown of the RHR system, the licensee identified that the RHR heat excha igers have high strength carbon steel (B7) studs installed in the shell/ head flange and, therofore, may be susceptible to boric acid attack since these flanges have been leaking. A s a part of the ACR's disposition, the licensee performed operability and i reportability deierminations. The inspector reviewed the licensee's records with the following observations discussed belo To determine the extent of a potential boric acid attack of the studs, tha licensee removed five studs with evidence of boric acid stains. The visualinspection performed on these studs revealed them to be in good physical condition; the studs exhibited good metal condition, full thread form and no pitting attack below the minor diameter of the studs, in addition, the licensee performed a magnetic particle (MT) surface examination of the studs and did not identify any circumferential flaws on the examined studs. There was no loss in material that would detrimentally affect the strength of the studs or impact the integrity of the joint. The structuralintegrity of the A and B RHR heat exchangers was never compromised. Therefore, the A and B heat exchangers were found operable. This operability determination was based on the good condition of the removed studs and the results of the MT performed on the studs. Further, reportability was not required because degradation of the pressure boundary did not occur, and the plant was not operated outside the design bases, Conclusion The inspector concluded that the licensee's actions to address ACR No. M3-96-0391 were adequate. The licensee's documentation and interviews conducted by the inspector with-the cognizant personnel showed sufficient evidence which demonstrated that the RHR heat exchangers were operable in their as-found condition due to the good condition of the examined studs, As a preventive action, the licensee will continue to monitor these studs by removing and examining five bolts every five years. SIL ltem 47 is close E8.2 Unsecured I-Beam Above Safetv Related Comoonents (SIL ltem 371 Insoection Scone (92903)

The inspector reviewed the actions being taken by the licensee to remove an unsecured structural member installed above safety-related components and the actions to prevent -

future installations of this nature, Observations and Findinos During a walkdown of Millstone Unit 3 on March 12,1996, an NRC inspection team found a temporary l-beam installed above three of the four recirculation spray system (RSS) heat exchangers. The licensee reported this condition to the NRC on March 13,1996, in accordance with 10 CFR 50.72, af ter determining that the I-beam had the potential to render both trains of the RSS inoperable during a seismic event. The licensee initiated ACR

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No.10382 to remove the l beam and to perform an engineering review of the hirtorical impact _on plant operations. The inspector walked down the areas and verified that the l-

- beam had been removed. An NRC team inspection. determined that this l beam removal was adequate corrective action. However, the team was concerned about the lack of - *

instructions or prucedures to prevent recurrence; documented as eel 423 20121, and part ,

of SIL ltem 3 '

In response to this NRC concern, the licensee revised Maintenance'and House Keepin Procedure No. OA8, Revision 0, which emphasized the proper storage, use and restraint of temporary structures or equipment installed above safety-related equipment. The inspector reviewed the procedure and found that it adequately addressed the NRC's concern and provided some clear guidelines for the restraint and installation of temporary structures above safety-related component c.- Conclusion r

The inspector concluded that the licensee's corrective action was adequate in addition, the licensee revised their maintenance and housekeeping procedure to provide engineering and maintenance personnel with a clear guidance for the restraint and installation of temporary structures above safety-related components. Therefore, the technicalissues involved with this item are closed, and SIL-ltem 37 is partially closed. eel 423/96 201 21 remains administratively open pending completion of enforcement action E8.3 IUodate) eel 423/96 201-24: Concrete Spalling of Service Water (SW) Pump Pedestal (Partial Closure) Sllitem 37: Corrective Action Effectiveness - Insocction Scoce (92903)

The inspector reviewed the licensee's actions taken to resolve the issues documented in eel 423/96-20124; :: palling of SW booster pump,3SWP'38, concrete pedestal. Spalling of the pedestal resulted in the pump being declared inoperable since the anchor bolts holding down the pump did not extend past the pedestalinto the concrete floor; thus the ability of the pump to withstand a seismic event could not be guaranteed. This condition had existed for an extended period of time and had not been identified and corrected by the license Observations and Findinas

' As corrective action, the SW booster pump pedestal was repaired and a protective coating wac applied to the pump pedestal. The licensee concluded that the pedestal damage-was caused by condensation enturing cracks in the concrete, causing the rebar to rust and expand. Other SW system components were inspected for similar conditions. Walkdowns ,

revealed that several other pump pedestals were cracked; however, the licensee determined that none of the cracks affected the seismic capability of the components. The anchor bolts for these components extended into the concrete floor. To prevent

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recurrence, the licensee revised procedure EN 31094, " Millstone Unit 3 System Engineer Walkdowns," to ensure that other equipment foundations are inspected durin-1 system .

. reviews.11n addition, procedure EN 31098, "MP3 Condition Monitoring of Structures," had

, been put in place uncier the Maintenance Rule to monitor safety-related Fiructures for structural degradatio The inspector reviewed the work orders and design change notices that were issued to

- repair the damaged components. Pedestals that were identified as~ cracked were repaired *

with Five Star Structural Concrete, and a protective coating was applied to the~ pedestals to-minimize water intrusion into cracks. A review of the manufacturbr's instructions' revealed that the concrete used for the repairs had a higher compressive strength than the concrete used for the original concrete pads, in addition, a walkdown of the auxiliary building revealed that all degraded pump pedestais had been repaired or were identified and scheduled to be repaired by the licensee, Conclusion The inspector concluded that the technical issue resolution and corrective actions for this particular concern were good. However, the closure of this issue does not address the overall effectiveness of the' licensee's corrective action program. Continued inspection of-the corrective action program will be reviewed as followup to SIL ltem 37. - SIL ltem 37 is partially closed. eel 96 201-24 remains open due to ongoing NRC considerations of potential escalated enforcement action involving this issu E8.4 (Ocen) eel 423/97-202-09: RSS Desian Deficiencv (Closed) LER 50-423/97-03. Potential RSS Water Hammer LER 50-423/97-15. Potential RSS Vortexing, LER 50-423/97-28, Potential Loss of RSS Pump NPSH, (Uodate) SIL item 85 Other RSS and Related Design Basis Concerns On January 13,1997, a licensee engineering evaluation determined that the recirculation spray system (RSS) heat exchangers and piping may be susceptible to water column separation, and subsequent water hammer events,if the RSS pumps are restarted during

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design basis accident conditions. On February 4,-1997, a licensee review of design -

' calculations ;dentified that the calculated minimum water levelin the containment sump at -

the time of the start of the RSS pump following a large break loss of cooling accident -

(LOCA) would be below the containment sump vortex suppression gratings. It was determined that cavitation of the operating RSS pumps could result from the air entrainment which would accompany the postulated vortex formation in the sump coolan On April 10,1997, another review of the design calculations for the net positive suction

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head (NPSH) for the RSS pumps identified the potential for steam flashing a.nd partial

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voiding of the coolant from the containment sump based upon suction line head losses in excess of the calculated availability of saturated coolant head condition __-_-

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All three of these licensee identified design deficiencies were reported to the NRC -

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- (respectively, LERS 97-03,97 15, & 97 28), within the required time frames delineated in

- 10 CFR 50.72 and 50.73, as conditions outside the design basis of the plant and,in the case of the NPSH concern, also as a loss of safety function.- The cause for all three events was determined by the licensee to relate to inadequate initial RSS design scope and to inadequate engineering review and process control during plant construction, i.e., prior to

- the issuance of the initial low power operating license, NPF 44, in November 198 =- Additionally, the above noted problems with the RSS design relate to c concern documented in LER 96-07, as supplemented, involving the RSS piping and suppo'rts being exposed to temperatures in excess of those for which stress analysis had been conducted prior to initial licensing. NRC inspection follow-up of this latter concern (i.e., LER 96-07) is documented in inspection report 50-423/96-06, concluding that the operation of the unit with the existence of such a design deficiency constitutes an apparent violation (eel 423/96-06 13) of regulatory requirements. The inspection documented in IR 96-06 also represents an update of SIL ltem 1, 3 In establishing the cause of the event documented in LER 96-07, the licensee determined that the identified " conditions have existed as part of the original plant design of the RSS (and other affected) systems." Also, LER 96-07 documents a condition in which the plant -

operated outside its design basis, resulting in the inoperability of, along with other analyzed

. systems, the RSS. The commonality of cause (initial design errors), effect (unit operation outside the analyzed design conditions),-and specific system impact (RSS inoperability),

that connects LER 96-07 with the other three LERs also supports the conclusion that the design deficiencies discussed in LERs 97 03,97-15, and 97 28 collectively represent an additional apparent violation (eel 423/97 202 09) of regulatory requirement The technical details, corrective measure implementation, and design changes intended to; address the problems discussed in these three LERs will be tracked with the apparent violation, as well as with this Update of SIL item 85. Therefore, LERs 97 03, 97-15, and 97 28 are herewith individually close E8.5 (Closed) URI 96-201-40 (Partial SIL ltem 11) Insoection Scone (92903)

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The inspector reviewed the engineering calculations and corrective actions taken to resolve m deficiencies in the engineering calculations to validate the operability of the turbine-driven tauxiliary feedwater pump (TDAFWP). The licensee had initiated, but'was unable to finalize,

- these evaluations during the specialinspection of engineering and licensing activities, and--

review of the final calculations was identified as an unresolved item, b, Observations and Findings ACR 13426, dated May 22,1996, was initiated to address deficiencies noted in the NUSCO engineering calculation 91-074-324M3, Rev. 0 (dated March 26,1983) used to validate the operability of the TDAFWP. The corrective actions to resolve the ACR included the acquisition of additional performance data for the turbine, the preparation of l

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new engineering calbulations, revision of the associated _ component' specifications and the -

FSAR. 'The inspector reviewed the new engineering calculations (Proto-Power Calculatio_n

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97-014 for TDAFWP performance and Proto-Power calculation 97-006 for pressure loss)

=

and found them appropriate and comprehensive. They were based on the new turbine

= performance data and included detailed estimates of pressure losses in the inlet and exhaust piping for the pump turbine. The calculations addressed the deficiencies ~noted,-. _

superseded the calculations in question, and demonstrated.the capability of the TDAFW to satisfy design requirements. The inspector reviewed the procurement specification (SWEC specification No. 2275.200-041) and the vendor specification (Terry Turbine specification No. OIM-041-003A) and verified that they and the Design Basic Document Package MP3-FWA for the AFW System, were modified to reflect the corrected performance requirements. Since the corrective actions include the performance of a flow test to assess the potential for flow induced vibrations, the inspector discussed the proposed test with the technical support engineer responsible for its performance. The engineer showed a c! ear understanding of test objectives, Conclusions -

The inspector concluded that the new calculations prepared by the licensee for ACR 13456-'

correct the deficiencies noted in the original calculation and provide the basis for evaluation of the TDAFWP overall performance._ The revised estimates of performance parameters show that the turbine / pump unit can meet design flow / power requirements. The affected '

unit performance specifications were corrected to reflect the revised performance parameters. Based on these findings, URI 96-201-40 is considered close E8.6 (Closed) SIL ltem 16: Dual Function Valve Control and Testing insoection Scoce (92903J In 1993 Millstone Unit 2 identified a problem with the operation of air operated valves in the letdown line. Specifically, the air actuator spring preload was not properly set such that adequate closing force was not available to close the valve against full reactor coolant system pressura. The inspector reviewed the licensee's evaluation for the applicability of

- this issue to Unit Observations and Findinas The cause of the problem on Unit 2 was attributed to a lack of procedures for performing .

maintenance on the vaive actuators which resulted in the' incorrect actuator spring preload adjustmen A review of this event by' Unit 3 personnel concluded that this issue was not a concern on Unit 3. This conclusion was based on the following:

e~ When the valves were purchased, a valve specific specification sheet was provided for each Unit 3 air-operated valve. .The specification sheet included the maximum required shutoff pressurr, for the valv *.

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The valve actuators were set up by the vendor to operate at the maximum shutoff pressure and the valve nameplates specify the air pressure bench settings that will-result in the proper actuator spring prelot e Unit ? maintenance procedures contain provisions for controlling the actuator settings and for post-maintenance testing to verify the actuator operates at the bench settings on the valve nameplat Conclusions The inspector reviewed valve specification sheets, maintenance procedures and a sample work order that performed maintenance on an air-operated valve. Based on these revie and discussions with licensee engineers, the inspector concluded that the licensee had adequately evaluated the event for applicability to Unit 3. Controls in place on Unit 3 should prevent a similar event on Unit 3. SIL ltem 16 is close E8.7 (Closed) Insoection Followuo item No. 50-423/96-08-17. (SIL 76): Fuse Ferrule Cracks

! insoection Scone (37551-10)

!

The fuse ferrule cracks became a concern when on September 11,1996, the licensee found several fuses (Shawmut Amptrap Cat # A2Y10) with axial cracks on their ferrules, that has been drawn from the warehouse for installation in Millstone Unit 3 (MP3). At that time, the licensee had developed a detailed plan to segregate all suspect fuses in the warehouse; to perform a 10 CFR Part 21 evaluation, and to 4 perform an operability determination of fuses installed in all units. In addition, the licensee, after consultation with fuse manufacturers and other utilities, had determined that the fuses with hairkne cracks on the ferrule were capable of performing the intended design function based on the a cailable industry experienc However, the licensee decided to perform an additionalindependent test to verify this industry position, Observation and Findinas The inspector noted that the fuses manufactured with brass ferrule material are suspectable to stress corrosion cracking, due to the brass ferrule material relieving internal stresses built up during the forming and crimping process. Both the fuse manufacturers (Gould Electronics by 1994 and Bussmann by 1985) had addressed this issue by changing the ferrule material design to a bronze or pure coppe The inspector determined that the licensee had performed an operability analyses on installed fuses and concluded that all fuses installed in the station were operabl The fuses with cracked ferrules met the required resistance values, current carrying capacity, clearing time-current requirements at 200% and 500% for the time delay fuses, and interrupting capability higher than expected value .

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The inspector also reviewed the licensee's engineering evaluation of Millstone Station (Unit Nos.1,2 and 3) concerning cracked fuses ferrule defects and noted that the licensee had appropriately issued a 10 CFR 21 notification report to the NRC on December 13,1996. The report indicated that the cracked fuse ferruie-problem existed in a variety of fuses from different manufacturers and indicated that fifteen different type of fuses from three different manufacturers (Gould-Shawmut, Bussmann, and CEFCO) had axial cracks, as a result of the brass ferrule relieving its internal stress as described above. The inspector noted that the licensee had completed the following planned corrective actions: Procurement and warehouse groups had completed inspecting all fuses for cracked ferrules and replaced suspect fuses with newly procured fuses, A metallurgical analysis on defective fuses was performed to determine the cause of the ferrule cracks. The analysis was found consistent with industry dat . Conducted an independent functional testing on defective fuses. The results from the testing indicated that the fuses met their intended function of maintaining electrical continuity and interrupting the current during overload I

and electrical faul . Established an appropriate certificate of conformance material type of requirements in their procurement documentation to purchase new fuses it ensure fuses being ordered were of new construction design either brass

, pure copper. Procurement also notified the manufacturer of this defect and l confirmed determined that they had taken corrective measure to address this I

concer . Completed the operability determinations on each Millstone unit and their evaluation concluded that the fuses installed were operable. Engineering departments of each unit has established a listing of safety related distribution fuses to include affected fuses. The license found that no defective style fuses were installed in Millstone 3. The licensee has elected to replace the defective style fuses in other units by an attrition basis as per their established routine preventive maintenance progra . Enhanced the procedure (NPM1-003, Rev. 2, by adding a note in it that if the material appears defective, material should be provided to the procurement engineering group for evaluatio The inspector randomly verified fuses stored in the warehouse and found that all fuses were free from above concern. The inspector also inspected fuses installed in electrical distribution equipment, such as switchgear, control power centers, motor control centers, and electrical distribution panels and verified that fuses installed in Unit 3 were not of a defective style fuses and exhibited no concern. The inspector noted that the fuses were properly labeled and easily identifiable.

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c. Conclusion The inspector concluded that the licensee had done an excellent job to resolve the fuse ferrule crack concerns at the station. Specifically,in Millstone Unit 3, most of the electrical distribution system fuses has been inspected and replaced with appropriate size new one with no cracks. The licensee engineering staff has conducted a through analysis to verify the industry position on fuse ferrule cracking to assure that the fuses installed in the station meet its intended design functio This item is closed.

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IV Plant SuoR9tt (Common to Unit 1, Unit 2, and Unit 3)

R1 . Radiological Protection and Chemistry Controls R 1.1 Review of ALARA Proaram

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i Insoection Scoce (83728 and 92904)

-The inspector reviewed the licensee's program for maintaining occupational exposures

. ALARA, including work cvntrol and planning, pre-job ALARA reviews, post job ALARA reviews and management involvement in the ALARA program. The inspector also reviewed

. actions taken to address previously identified violations of NRC requirements in the area of-radworker performanc s Observations and Findinas Unit 1 Unit 1 established an ALARA Council through the implementation of procedure RPM 1.4.3,-

Rev 0, " Unit 1 ALARA Council." Council membership consists of the Directors for Operations, Work Management, Maintenance and l&C, Engineering and Support Services, together with the Radiation Protection Manager (RPM). The inspector reviewed the activities of the council by discussion with members of the Unit ALARA staff and review of the Council meeting minutes. Prior to the establishment of this council, unit management involvement in ALARA activities was minimal, and thus creation of the council and participation at the director's level represents an improvement in the program,-

For 1997, the unit ALARA goal was recently lowered by 200 person rem to 198 person-rem, to reflect the very limited amount of work still to be performed during the remainder of 1997. Through July 10th, unit occupational exposure was just above 164 person-rem and was tracking well against licensee projections. Following the decision to defer most work in the unit until 1998, the ALARA staff began closing most ALARA review packages, obtaining worker comments , and compiling lessons learned. When work recommences, these reviews will aid in establishing appropriate ALARA controls on these unfinished job During the last specialist inspection in this area (NRC Inspection 50-245/97-02), several-examples of improper radworker practices were identified.- Subsequent to that inspection,

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the licensee undertook a Common Cause s.1alysis, documented as." Adverse Trend in - !

Personnel Performance Across Millstone Site." This analysis concluded that there were ,

.four primary root causes, three related to management. Of significance was the recognition'in the analysis that radworker practice problems were not solely a Radiation -

Protection Department issue but was a site-wide problem requiring actions be taken by all }

-radiological workers and their supervisors. While many of the corrective actions required to j address the findings were not implemented at the time of this inspection, the heightened-awareness by radworkers and their supervisors was evidenced by the significant reduction in the number of documented instances of improper radworker practices. This was

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confirmed by the results of the inspector's observations of radworkers in the Radiologically Controlled Areas (RCA). Actions taken in Unit 1 included training sessions and unit walkdowns conducted by the RPM, and a reduction in the number of access points into the unit RC Unit 2 Unit 2 has established an ALARA Committee which includes representatives from each of the major departments and is chaired by the Unit Director. Meetings are held every two months at a minimum, and the directors of the major unit functional areas are required to attend at least two of the Committee meetings in person. As part of this inspection, the inspector attended the ALARA Committee meeting held on July 10,1997. The inspector noted the scope and depth of discussions held during the meeting as being appropriat Committee members were observed being proactive in their discussions and actions to address personnel exposure issues and to plan for improvements in the ALARA progra The annual exposure goal for the unit remains at 182 person rem, and a summary of daily exposures is presented daily at the Unit Director's morning staff meeting and reviewed in detail. Exposures were on track with the licensee's predictions, and the unit goal continues to appear attainable, i

Unit 2 had experienced the largest number of documented instances of improper radworker practices, three each cited in NRC Inspection Reports 50-336/97-01 and 50-336/97-0 Since the last specialist inspection in this area, however, no additionalinstances have been identified, As part of this inspection, the inspector toured the containment and auxiliary buildings observing work areas and radworkers. No radworker discrepancies were identified by the inspector. Enhanced controls included the closing of some satellite RCA access areas, the continued assignment of a health physics technician to check workers dosimetry prior to RCA entrance and more effective posting of the main RCA access doo Unit 3 Unit 3 had the largest amount of work and workers in the RCA at the time of this inspection. The unit ALARA goal remained at 134 person-rem, and exposures were tracking well with the predicted _ values. Significant radiological work still tc be' completed included the replacement of all four reactor coolant pumps. Activities in support of the ALARA area remained weak, especially those actions outside of the Health Physics Department. No ALARA Committee has been formed at Unit 3, which was identified as a weakness in a recently completed Nuclear Oversite Audit, MP-97 A06-02, " Radiation Protection,"_ dated June 27,1997. In addition, wck control and planning remain very erratic and incomplete at the unit with respect to advanced planning and scheduling. An earlier attempt at creation of a 12-week planning schedule was suspended in the spring in favor of an outage planning and management system. That too was abandoned after only two months, with the unit again looking at a 12-week planning schedule, in general, occupational exposures at Unit 3 have remained low due to the very low dose rates found at the unit, not because of any efforts in support of an ALARA program. Discussions held with the Unit Vice President / Recovery Manager indicated that the ALARA program

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weaknesses were clearly recognized as needing management attention, and that the creation of an ALARA Committee was also to be addresse Improper radworker practices were identified in NRC Inspection Report 50-423/97 0 Since that specialist inspection, the Unit has significantly upgraded the level of interaction and briefings given to radworkers prior to entrance to the RCA through the main RCA control point, located at the entrance to the auxiliary building. The entrance was also recently equipped with a turnstile that could only be activated if the radworker placed both -

his electronic dosimeter (ED) and thermoluminescent dosimeter (TLD) in it. This is utilized to reduce the chances of a worker accessing the RCA without having the appropriate dosimetry with him. The inspector observed workers entering and exiting from this area, and also observed a number of workers in the RCA, including the ESF, spent fuel and auxiliary building. All workers observed had proper dosimetry and were aware of their area dose rate The inspector also attended a training committee meeting hosted by Unit 3 involving radworker training. At the time of this meeting, all station training was suspended, and the major theme of this meeting was to identify and resolve allissues related to radwot.ser training so that this program could recommence as soon as possible (Radworker training recommenced on July 10,1997). The inspector noted that the Training department staff present served as facilitators, but that ownership of the training program clearly rested with the units. Good coordination and communications between the three unit RPMs was also observe Site Health Physics

. The inspector reviewed parts of the site radiation protection program under the direction of the Site Health Physics Manager and his staff. The inspector reviewed Condition Reports (CRs) and other records maintained by this staff for compliance with NRC rules and requirements. Allincidents and events requiring a CR by station procedure were found to be so documented. The inspector also discussed with the Site RPM and his staff an event involving the discovery of an unlocked door to the trailer located at the radwaste bunker on May 5,1997. This event was not documented as a CR, nor was a CR required. The event was documented in the Site Health Physics Support Groups daily log book. Following conversations with the inspector, the Site RPM determined that, although not required, for tracking and trending purposes, a CR should be written to document the even Subsequently CR M1-97-1685 was written on July 9,1997, Conclusions The program for maintaining occupational exposures ALARA at each of the three units remains weak. While the framework for an ALARA program has been implemented at Units 1 and 2, with the creation of an ALARA Committee and the implementation of an operational work control and work planning group, neither have been established for a long-enough period to fully evaluate their effectiveness. The continuing lack of an effective work control and planning process together with the lack of a unit ALARA Committee at Unit 3 continues to be of concern, however. Licensee actions to address radworker practice issues have been generally effective, although long-term actions are still being implemente .--

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i 69 i' R5 Staff Training and Qualification in Radiological Protection o.d Chemistry l Controls 1

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R5.1 Health Physles "Suoervisors Walk Around"

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i Insoection Scone (71760)

! On June 25,1997, the inspector participated in a health physics (HP) " supervisors walk-

around" with the radiation protection manager (RPM). Plant management sponsored the

$

plant walk-arounds in order to raise the HP awareness of supervisors observing day to day l work activities in the field.- The walk-arounds were mandatory of all Unit i supervisor '

l i

' Observations and Findinas J -

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1 The walk around was conducted by the RPM and began outside the radiological controlled :i

! area (RCA) with a review of the radiological work permit system and the proper use of i electronic dosimetry. Once inside the RCA, the RPM discussed the operation and use oi ;

} the small article monitor (SAM) and personnel contamination monitor. A primary focus area - ,

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for the walk around was the use of reusable materials in the plant, particularly in the area of FME control. The RPM stressed the fact that limiting the amount of disposable material '

brought into the plant, results in a reduction in radiological waste (RW). Plans for a " hot

{ tool" locker In the plant were also discussed.

I ;

The tour was extremely informative and provided good insights into RW reduction. The L 4 walk arounds received very good response * rom de plant staff and as of the end of June, i 78 of 80 Unit 1 supervisors attended, and 79 additional personnel participated in the -

activity, including individuals from Unit 3. The inspecW was informed that additional 3 walk arounds are planned for other HP areas, for example HP pont5g and boundaries, as well as, walk arounds in the areas of security and nuclear oversigh !

4 Conclusions i

i Plant management sponsored the plant supervisors walk arounds in order to raise the HP awareness of supervisors observing day to d y work activities in the field. The walk-

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around tour was extremely informative a rd provided good insights into radiological waste

reduction. The initiative as well received by the Unit 1 supervisors and will be expanded to

included additional ares such as security and ruclear oversigh ,

j P4 Staff Knowledge and Performance in Emergency Preparedness i

? P Drill Evaluation Scone

'

. t 4 insoection Scone

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During this inspection, the NRC inspectors observed and evaluated the performance of the i

licensee's site emer0ency response organization (SERO) during the drillin the simulator '

control room (SCR), technical support center (TSC), operations support center (OSC), and i

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tne emergency operations facility (EOF). The inspectors assessed licensee recognition of abnormal plant conditions, classification of emergency conditions, notification of of fsite agencies, development of protective action recommendations, command and control, communications, and the overallimplementation of the emergency plan, in addition, the inspectors attended the post exerciso critique to evaluate the licensee's self assessment of the drill, Observations and Findinos Emeroency Resnonse Facilitv Observations and Critioug Simulator Control Room (SCB1 During this drill, the shift manager demonstrated excellent command and control of the l operations crew. Good internal communications were evident between the unit supervisor ,

and the control board operators, to include strong " repeat-back" techniques, good use of !

the alarm " master silence" feature, and proper use of the emergency operating procedure The shif t manager conducted initial classification of the event at the " Alert" level in a timely manner and with proper consideration of the criteria delineated in the event assessment procedure, EPIP 4400, Communications with the technical support center i

(TSC) was established and maintained effectively. However, it was noted that the shif t manager transferred the responsibility for emergency classification to the assistant director of technical support before full TSC functional capability had been verified end that this transfer of duties was not announced to the control room staff at the earliest opportunit Once a direct communications link was established with the TSC, frequent briefings and

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discussions took place on plant conditions, equipment status, and the analysis of this event. The control room staff was particularly effective in discussing options and operating decisions with TSC personnel before commencing or altering planned evulutions. This deliberative coordination was found to be in evidence in the decit:ons to start and then

- secure the "C" charging pump, to not reopen the accumulator isolation valves after resetting the initial safety injection signal, and to start and secure quench spray pump operation as necessary. Also, the shif t manager performed wellin assessing and projecting the potential for further radiation barrier degradation and in discussing the appropriate recommendations with the TSC staff. One area where coordination between the control room and the TSC could have improved was the control and tracking of various support personnel (e.g., chemistry, health physics, field teams) that were dispatched for work activities from either of these two locations without the clear and direct knowledge of all concerned managers and/or coordinator The control room staff had a good focus on maintaining a safe and stable unit, given the

- changing plant conditions and equipment abnormalities. The unit supervisor conducted appropriate critical safety function reviews and worked with the shift manager in prioritizing control room activities and evolutions and in attempting to provide "real time" information to both the TSC and the Emergency Operations Facility (EOF), Anomalous plant conditions (e.g., increasing containment pressure indications and radiation levels)

were diagnosed and discussed by the licensed control room operators with input from the

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j shif t technical advisor and station duty officer, to provide both the TSC and EOF with the

best collective analysis of what might be causing any observed worsening emergency j conditions, j

1 One area where better external control room communications and coordination could have

) been provided was that of the " turnover" of functional responsibilities to designated i

' personnelin the other facilities. In addition to the possibly premature transfer of event !

classification duties discussed above, it was noted that the station duty officer delegated -l l the responsibility for initially notifying NRC headquarters of the " Alert" to the EOF

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information officer before the shif t manager had turned over command and control of the i emergency to the Director of Station Emergency Operations (DSEO). It is routinely

! expected that the initial telephone communications with the NRC duty officer would -

originate from the control room, vice the EOF. Also, the shif t manager's turnover of

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command and control to the DSEO appears to have occurred prior to actual activation of ;

the EOF.

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l While some turnover and coordination problems involving the control room's interaction

with both the TSC and EOF were observed, the overall response of the licensed operators, l shif t management, and the entire control room crew were determined to be good, with

! positive impact upon both the assessment and steps taken to mitigate the emergency !

{ conditions.

}

l Technical Suonort Center (TSC) Ooerational Suocort Center (OSC)

J

! The TSC was staffed and activated in a timely manner. The Assistant Director of l Technical Support (ADTS) exhibited strong command and control, and rnalntained good j communications with the simulator control room throughout the drill. The ADTS conducted'

a good turnover from the shift manager and ensured that his staff was briefed prior to ;

i activation. However, the ADTS accepted responsibility for emergency classification from l the simulator control room prior to officially activating the TSC. Additionally, the inspector noted that there was some confusion as to when the TSC was activate ;

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l Event classifications were_ correct and timely, and notifications of offsite officials were l appropriately initiated. Although, af ter the declaration of the Site Area Emergency (SAE)

i and the General Emergency (GE), the declarations were not announced to plant personnel F via the public address system, in evaluating the Emergency Action Levels (EALs) for

!

escalating from a GAE to a GE, the ADTS-was noticeably focused on the barrier failure portion of the EALs, and1ha barrier failure reference table. The apparent difficulty in the

[ use'of this pcrtion of the EAL distracted the ADTS from other applicable EALs, As the drill'

i progressed,' the ADTS was reminded by the Director of Site Emergency Operations (DSEO)

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in the EOF, that a GE can be: declared directly from the in plant radiation EAL regardless of .

barrier failure cr,iteria.

L I During regular and frequent briefings, the ADTS ensured that priorities were properly-

! established and understood by both the TSC and OSC members. The Manager, Operational j Support Center (MOSC) and the Manager, Technical Support Center (MTSC) were both

[ given the opportunity to provide a status of reports at each of the briefings. This allowed i

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for the close coordination of activities between the TSC and the OSC. Three way communications (repeat backs) were consistently and effectively used by all TSC/OSC members. The ADTS kept the TSC staff thinking ahead in anticipation of changing plant conditions by the use of a white board and continually asking the question, "What can go wrong?" The use of backup ADTSs during this drill was excellent in that it removed some of the administrative and communication burdens from the ADT The MTSC coordinated with the accident management team to evaluate potential adverse consequences of the events, keeping the ADTS advised of the changing priorities. The accident management team played an important role in assessing the scenario in light of erroneous information (containment radiation levels) from the simulator control roo The ADTS appropriately established and adjusted the priorities of emergency repairs. The MOSC maintained a good command and control over the OSC. Team activities were closely monitored and teams were dispatched in an orderly f ashion depending on changing priorities. All OSC teams were briefed by HP prior to being dispatched.

l Emeraenev Ooerations Facilitv (EOF)

Good command and control was demonstrated by the Director of Site Emergency Operations (DSEO) and the Assistant Director of the Emergency Operations Facility (ADEOF). The DSEO gave thorough briefings to the EOF staff. The DSEO effectively used the team leads to prcvide information to the other staff members during the briefings in the emergency operations center. However, it appeared that the DSEO was having problems getting the plant status information through the open link used to transfer information from the simulator control room and the technical support center. This lack of information could have been a hindrance in some of the decision making in formulation of the protective action recommendations provided to the state of Connecticu The technicalinformation coordinators did a very good job in maintaining the status boards and informing the DSEO of plant conditions as they changed, through direct communications from the simulator control or from the Offsite Facility Information System (OFlS).

The ADEOF's performance in preparing the PAR for the DSEO using the new, approved PAR procedure in formulating the initial PAR on plant conditions at the general emergency and the PAR upgrade which was caused by a change in plant conditions later in the <jrill was good Because the new PAR procedure is the same for Haddam Neck, and it was adequately demonstrated during this drill, the Haddam Neck violation on formulation of PARS is close Dose Assessment The radiological dose assessment team monitored plant parameters and calculated the number of the curies of noble gases in the containment based upon the containment radiation monitor reading. The dose assessment team informed the Assistant Director Emergency Operations Facility (ADEOF) of the dose consequences which may occur if the j

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entire containment source term was released from the worst release point. This information was used in providing a worst case estimate of potential consequences, but could cause inappropriate protective action recommendations (PARS) to be issued if the recommendations were based upon this information. The ADEOF considered this information, but properly based his PAR upon the current plant conditions as a release was not ongoing nor predicted to occur. It would have been beneficial for the dose as:essment team to provide additional "what if calculations for other release points and other release magnitude Although the radiological dose assessment team was able to make dose projections and position field teams to monitor the release, the following aspects of the radiological dose assessment was not well performed:

Dose assessment personnel were not proficient in the use of the Offsite Facility .

Information System (OFIS). OFlS can be used to rnonitor containment radiation levels and vent stack monitor reading * When it was oiscovered that the OFiS readings lagged the actual plant readings, the dose assessment team did not aggressively pursue obtaining more timely radiation monitor data from another sourc * The start of the release was not quickly identified by the dose assessment staff and was not clearly communicated among the EOF staff and field monitoring team * Dose projection calculation sheets were not properly filled out. One of the dose assessment sheets contained an error and other calculational sheets did not have all

- the pertinent data entered. Sheets were not signed and dated. Very little hard copy doso projection data was printed out. This data could have been usefulin tracking the update in dose projections during the event and would have been usefulin evaluating the dose projections af ter the event / dril Licensee Drill Critiaue Th3 licensee's critique was very comprehensive and thorough, it identified all of the observations identified by the NRC inspection team, Qyerall Drill Conclusions

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Overall performance of the SERO was good. Simulated events were accurately diagnosed, l proper mitigation actions were performed, emergency declarations and protective action l recommendations were timely and accurate, and offsite agencies were notified promptly No drill weaknesses, safety concerns, or violations of NRC requirements were observed.

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P8 Miscellaneous Emergency Preparedness issues insoection Scoce On Tuesday, June 17,1997, the inspector and Emergency Preparedness and Safeguards Branch Chief met with the Northeast Utilities Director of Emergency Preparedness and his staff and were presented with the " Millstone Station Emergency Planning Status."

The presentation included past issues, issue resolution, emergency planning elements that were in progress, milestones completed, and milestones remaining. A copy of the presentation handout is attached. The corrective measures being taken are appropriate.

I Observations and Findinas The inspector observed a test of the new dialogic callout systems that is scheduled to replace the present system that is currently in use. The pagers were activated at approximately_7:00 p.m. on June 18,1997. It was demonstrated to the inspector by calling into the system that the initial call backs seemed to overload it initially, but within 2-to 3 minutes we were able to callinto the system. Within about 20 minutes, the callout was complet A message was displayed on the beepers that if there were any problems getting into the system that personnel were to contact the emergency preparedness services c;epartmen There,were severalinstances where the PIN number f or the beeper holder did not work properly and that was to be correcte The system appeared to function and made timely notification to the site emergency response organizatio Further tests of the system are to be performed before placing it into operatio F1 Control of Fire Protection Activities-F Proaram Overslaht insoection Scone (64704)

The inspector reviewed fire protection program policy changes made by licensee management to improve program oversight. This review was performed as a result of previous NRC inspection findings, as documented in Inspection Report No. 96-08, Section Obseivations and Findina_s The inspector found that the licensee continued development of the Fire Protection Program Manual. Although lacking supervisory approval of the manual, the inspector reviewed the licensee's documented efforts for integrating design features, personnel requirements,

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equipment, and procedures to ensure fire protection requirements are met. Following document approval, the licensee plans to develop supplemental guidance documents, oroject instructions, to the manual for controlling fire hazards analyses and 10 CFR Part 50, appendix R analyse The inspector found the manualimproved over Nuclear Group Procedure (NGP) 2.14, Revision 9, * Nuclear Plant Fire Protection Program," and reflected the program organizational changes to date, better defined individuals responsibilities, and appropriately established a single point of control and contact for improved program implementation. In addition, the inspector noted that information pertaining to the design and licensing

, requirements for the three Millstone plants was contained within the draft manual. The

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inspector noted that the manual presented an expanded view of fire protection compared to the NGP More specifically, the inspector found that the manual applied to fire protection structures, systems, and components important to-safety in addition to safe shutdown and safety related equipment. Although fullimplementation of the licensee's corrective actions had not been completed, and subsequently the inspector could not evaluate the effectiveness of such actions, the inspector concluded that positive measures were taken by a competent staff for establishing a good fire protection program and consistent approaches for maintaining the program in accordance with NRC requirements. The inspector noted that the manual was approved without any changes from the draf t version

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reviewed during the inspection on July 2,1997, by the Site Operations Review Committee (SORC) and on July 9,1997, by each Millstone unit Plant Operations Review Committee (PORC).

Corrective actions taken by the licensee to improve the effectiveness of engineering support for the fire protection program, as discussed in Inspection Report 96-08, boction F.1, were not evaluated during this inspection and will be the subject of future NRC review =

prior to restart of any Millstone unit. (IFl 97 20210) The acceptability of the licensee's corrective actions will be used to substantiate closure of NRC safety issues list (SIL) issues Nos. 65,21, and 42 for Millstone Unite 1,2, and 3 respectivel The inspector found that corrective action taken by Northeast Utilities included the performance of an engineering self assessment (ESAR) No. PES 97-OOO6, Revision 0, for evaluating the licensing commitment control, configuration management, technical adequacy, and effectiveness of the Unit 3 fire protection / Appendix R program. This assessment was conducted by an independent team and resulted in numerous deficiencies and corrective actions. The licensee stated that ESARs were planned for Units 1 and 2 also. The inspector determined that the ESAR was comprehensive for verifying compliance with regulatory requirements and qualitative for recommending corrective actions that would ensure an effective fire protection program. The inspector found that license commitments were extensively summarized with background and reference information sufficient to verify proper plant configuration and adequac Conclusion The inspector concluded that significant progress had been made by the licensee in improving the oversight and organization of the fire protection program. Although planned i

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corrective actions were found to be comprehensive, further NRC review is necessary to verify the proper implementation of the planned corrective action F4 Fire Protection Staff Knowledge and Performance F Fire Brigade Drill Insoection Scone (64704)

The inspectors observed an unannounced fir 6 drill to evaluate the effectiveness of the new centralized fire brigede, the drill scenario, and the drill critique. This observation was made as a follow up to previously identified drill weaknesses, cs documented in NRC inspection report 90 08, section F Observations and Findings The inspector observed a fire drill on June 24,1997, that involved a simulated motor control center breaker fire in the turbine building of Unit 1. The inspector observed the brigade response, dress out, simulated attack strategy, and command and control '

demonstrated by the brigade captain. The inspector found that many improvements had been implemented by the licensee. Scenario cards were utilized at the fire scene to describe fire conditions and enable fire brigade members to size up the situation and develop their fire fighting strategy. A newly created position of fire brigade advisor was utilized as an Operations department liaison, communicating information between the control room and brigade captain. An emergency response vehicle was used to expedite brigade arrival at the fire scene by transporting fire gear. A pre drill meeting was held to better ensure proper drill coordination and evaluation by both the Training and Site Fire Protection departments, and a post-drill caucus was held prior to the drill critique to ensure consistent feedback was provided to the brigade regarding their performanc The inspector found that:

the drill scenario was realistic; e excellent support was provided to the brigade captain by the fire brigade advisor:

the fire captain demonstrated outstanding command and control and verified self~

checks were performed by the brigade, properly reviewed the pre fire plan, and made team assignments accordingly; e drillmanship and teamwork were robust; and e the drill critique properly reflected brigade member performanc .

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i Conclusion

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The inspector concluded that the fire brigade functionad effectiv6 and was well prepared

to combat fires. Significant improvements were implemented by tne licensee that contributed to overall superior performance displayed by the Training and Site Fire Protection Departments associated with the fire drill. The inspector considered the drill to be outstanding and concluded that significant improvement was displayed by both the ;

] brigade and training department ,

F7 Quality Assurance in Fire Protection Activities

F Audits and Surveillances

l Insoection Scone (64704)

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The inspector reviewed the most recent audit completed by the Quality Assurance (QA) !

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Nuclear Oversight Department to satisfy the technical specification requirements. The i

audit evaluated the effectiveness of fire protection measures, equipment, program i implementation, and problem identification and resolution. This review was performed 4-following previously identified audit weaknesses as documented in NRC Inspection Report'

i No. 96 08, Section F '

i Observations and Findinas -

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The inspector reviewed audit no. A24057/A25119, " Triennial Fire Protection program -

, Millstone," dated Mar 1110,1997, and found that the audit:

* was comprehensive and appropriate in scope;

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e demonstrated good problem identification;

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appropriately followed up on previously identified QA findings; and

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e clearly communicated findings in reports.

c.- Conclusion

The inspector concluded that this OA audit provided a good assessment of the fire protection program and satisfied the technical specification requirement for performanc s The inspector noted an improvement in the assessment quality over previous audits of the-

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fire protection program,

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V. Management Meetings l X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at separate meetings in each unit at the conclusion of the inspection. The licensee l- acknowledged the findings presente X1.2 Final Safety Analvsis Reoort Review

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l A recent discovery of a licensee operating their facility in a manner contrary to the updated l final safety analysis report (UFSAR) description highlighted the need for additional verification that licensees were complying with UFSAR commitments. All reactor ;

inspections will provide additional attention to UFSAR commitments and their incorporation l l Into plant practices, procedures and parameters,

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While performing the inspections which are discussed in this report the inspectors reviewed- '

- the applicable portions of the UFSAR that related to the areas inspected. The following

inconsistencles were noted between the wording of the UFSAR and the plant practices, .j l procedures and/or parameters observed by the inspectors, as documented in Sections l U3.M1.3, U3.M3.2, and U3.E i

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ITEMS OPENED, CLOSED, AND DISCUSSED Onened URI 50 245/97 202-01 U 1.E RWCS filter cubicle inspection URI 50-336/97 202-02 U2.E Main steam check valves design adequacy IFl 50 423/97 202 03 U3,0 Loss of spent fuel pool cooling VIO 50-423 97-202-04 U3.M Failure to follow procedures IFl 50-423/97 202-05 U3.M Testing of safety / relief valves eel 50 245/336/423/ U3.M Inef fective maintenance and technical training 97 202-06 evaluation IFl 50 423/97 202 07 U3.M Letdown heat exchanger ASME code compliance l VIO 50-423/97 202 08 U3.E Incomplete and inaccurate information eel 50 423/97 202-09 U3.E RSS design deficiency IFl 50-423/97 20210 U3.F1,1 Engineering support of fire protection program Closed URI 50 245/9414 03 U1,M QA involvement in safety related work IFl 50 336/95 20103 U 2.M Procedure level of use IFl 50 336/93 20-05 U2.E Testing of dual function valves URI 50-336/96-0814' U2.E Removal of startup rate trip URI 50 423/96-0818 U3.M Adequacy of IST program URI 50-423/96 20140 U3 E8,5 TDAFW calculations c

Uodated eel 50 336/96 20125 U 2.E eel 50-336/96 20136 U2.E eel 50-336/96 20142 U2 E8,5 eel 50-336/96 20143 U2.E LER 50-423/9515 02 U3 E URI 50-423/95 0710 U3.E eel 50-423/96 20121 U3.E eel 50-423/96 20124 U3.E The followino LERs were also closed durina this insoection:

Docket Nursber 50-336 97-04 97 11

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Docket NumberJDf23 96 34 9650 97 03 97 14 97 15 97 22 97 23 97 24 97-20 97 28

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LIST OF ACRONYMS USED ACP(s) administrative control procedure (s)

ACR(s) adverse condition report (s)

ADEOF Assistant Director of the Emergency Operations Facility i ADTS Assistant Director of Technical Support AFW auxiliary feedwater AITTS action item tracking and trending system i ALARA as low as reasonably achievable ANSl/ANS American National Standards institute /American Nuclear AUO(s) anticipated operational occurrence (s)

ASME American Society of Mechan' cal Engineers AWO(s) automated work order (s) ;

BOM bill of materials CAC(s) curriculum advisory committee (s)

CCP reactor plant component cooling CFR Code of Fe;eral Regulations CMP configuratic n management plan CR(s) condition ieport(s)

CREPS control room envelope pressurization system DCN design change notice DSEO Director of Station Emergency Operations EAL(s) emergency action level (s)

EDG cmergency diesel generator eel escalated enforcement item EOF Emergency Operations Facility EOP(s) emergency operation procedure (s)

EPIP(s) emergency plan implementing procedure (s)

EPRI Electric Powei Research Institute ERT event review team ESAR engineering self-assessment report EWR(s) engineering work request (s)

FME foreign rnaterial exclusion FP fire protection FSAR Final Safety Analysis Report GE General Electric GL Generic Letter gpm gallons per minute HELB high energy line break HPSI high pressure safety injection HX heat exchanger ICAVP Independent Corrective Action Verification Program IFl inspector follow item IHSI intermediate head safety injection IP(s) intpection procedure (s)

lR(s) Inspection Reports (s)

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IRT independent review team ISI inservice inspection IST in service testing LER(s) licensee event report (s)

LOCA loss of coolant eccident LTOP low temperature overpressure protection MCR Main Control Room MEPL material, equipment, and parts list MMOD maintenance modification MOSC Manager, Operational Support Center MSIV main steam isolation valve MTL- management test lead MTSC Manager, Technical Support Center l

MSLB - main steam line break

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NCRp! nonconformance report (s)

NCV non cited violation NDE non destructive examination NGP(s) nuclear guidance procedure (s)

NNECO- Northeast Nuclear Energy Company's NPS nominal pipe size NPSH- net positive suction head NRC Nuclear '<.egulatory Commission NRR Nuclear Reactor Regulation NSAB nuclear safety assessment board NSIC Nuclear Safety information Center NSR .

nonsafety related NUQAP Northeast Utilities Quality Assurance Program NUREG - Nuclear Regulation NUSCO Northeast Utilities Service Company -

OCA Office of Congressional Affairs OEDO Office of Executive Director for Operations OFIS offsite facility information system

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OIR(s) open item report (s)

OJT on the job training OJT/E . on the job training / evaluation OP(s) operating procedure (s)

OR Operational Readiness Plan OSC Operational Support Center OSHA Occupational Safety & Health Administration PAO' Public Affairs Office PDCR plant design change record PDR Public Document Room PEO plant equipment operator PGS primary grade water system PM MS .- production maintenance management system -

PORC : plant operation review committee PORV(s) power operated relief valve (s)

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PSTS ' product specific technique sheet PTSCR proposed technical specification change request-QA quality assurance OC quality control OSS quench spray system

, - RBCCW- reactor building closed cooling water

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RCS reactor coolant system RG Regulatory Guide

RHR residual heat removal L- RI- Region I RO reactor operator l RPM radiation protection manager i RSS recirculation spray system RW radiological waste ,

RWCU- reactor water cleanup

. SAT-- systems approach to training SBLC standby liquid control SCR simulator control room SERO' station _ emergency response organization SFPC spent fuel pool cooling--

SIL _

significant item list SORC site operations review committee SOV(s) solenold operated valve (s)

SPIs) - surveillance procedure (s)

SPO Special Projects Office SPROC special procedure SR safety related SRO senior reactor operator SRP Standard Review Plan SSPS solid state protection system SWEC Stone & Webster Engineering Corporation SWSOPl service water system operational performance inspection TAC technical advisory counsel TDAFW- turbine driven auxiliary feedwater Tl- temporary instructio TLD(s) thermo luminescent dosimeter (s)

TRM Technical Requirements Manual

- TS(s): technical specification (s)

TSC ' Technical Support Center UFSAR: updated final safety analysis report UIR(s) unresolved item report (s)

URl(s) unresolved item (s)

USQ unresolved safety question VIO violation J

v t e Inspection Report - Millstone - 1997202 (Security)
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1997 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 12(0) 81(0) 85(0) 80(0) 84(0) 82(0) 83(0) Security 202(0) 203(0) 207(0) 208(0) 212(0) 211(0) 201(0) 206(0) 209(0) 210(0) Operator Exams Emergency Planning Other

IR 05000245/1997202

Text

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