IR 05000245/1996009

Insp Repts 50-245/96-09,50-336/96-09 & 50-423/96-09 on 961026-1231.Violations Noted.Major Areas Inspected: Operations,Maint,Engineering & Plant Support

ML20135E616
Person / Time
Site:	Millstone
Issue date:	02/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20135E602	List: ML20135E600 ML20135E611 ML20135E616
References
50-245-96-09, 50-245-96-9, 50-336-96-09, 50-336-96-9, 50-423-96-09, 50-423-96-9, NUDOCS 9703070183
Download: ML20135E616 (90)

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l U.S. NUCLEAR REGULATORY COMMISSION

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REGION I

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Docket Nos.: 50-245 50-336 50-423 l Report Nos.: 96-09 96-09 96-09 l License Nos.: DPR-21 DPR-65 NPF-49 l l

Licensee: Northeast Nuclear Energy Company l P. O. Box 128 l Waterford, CT 06385

Facility: Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at: Waterford, CT Dates: October 26,1996 - December 31,1996 f

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Inspectors: T. A. Easlick, Senior Resident inspector Unit 1 I

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l A. C. Cerne, Senior Resident inspector, Unit 3 A. L. Burritt, Resident inspector, Unit 1 D. P. Beaulieu, Acting Senior Resident inspector, Unit 2 R. J. Arrighi, Resident inspector, Unit 3 J. T. Shedlosky, Senior Reactor Analyst, Rl/DRS  !

J. D. Wilcox, Jr., Senior Operations Engineer, NRR/DRCH/HOMB i J. H. Williams, Senior Operations Engineer, Rl/DRS D. T. Moy, Reactor Engineer, Rl/DRS l L. A. Peluso, Radiation Physicist, Rl/DRS G. C. Smith, Senior Physical Security inspector, Rl/DRS J. T. Furia, Senior Radiation Specialist, Rl/DRS l J. H. Lusher, Health Physicist, Rl/DRS  :

L. L. Scholl, Reactor Engineer, Rl/DRS l Approved by: Jacque P. Durr, Chief Inspection Branch j Special Projects Office, NRR

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l 9703070183 970224 l PDR ADOCK 05000245 l 0 PDR ._ . _ _ _ - _ _ _ _ _ _ ._ _ _ .. - _.-

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TABLE OF CONTENTS i

EXE CU TIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv t i

U1.1 Operations .................................................. 1 .

U106 Operations Organization and Administration . . . . . . . . . . . . . . . . 4  :

U107 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . 10 '

U 1. Il M aintena nce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 i U1 M1 Conduct of Maintenance ....................... .... 11 U1 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . 12  ;

U 1.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 -

U1 El Conduct of Engineering ............................. 13 U1 E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . 16

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U2.1 Operations ................................................. 21 {'

U2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 U2 03 Operations Procedures and Documentation ................ 24 .

U2 05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . 25 l

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U 2. ll M ainte na nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 )

U2 M1 Conduct of Maintenance ............................ 29 i U 2.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 U2 E1 Conduct of Engineering ............................. 31

U3.1 Operations ................................................. 35 l U3 01 - Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 U3 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . 36 )

l U3 08 Miscellaneous Operations issues (92700) ................ 38 J U 3. Il M ai nt e na nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 3 U3 M1 Conduct of Maintenance ............................ 38

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i l USM2 Maintenance and Material Condition of Facilities and Equipment ...................................... 41 U3 M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . 43 U3M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . 48 )

i U 3. lli Engine e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 U3 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . 49 U3 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . 54 IV Plant Support ................................................. 57 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . 57

. R2 Status of Radiological Protection and Chemistry Facilities and Equipment ...................................... 60 ii

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R5 Staff Training and Qualification in Radiological Protection and f C he m i s t r y . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

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R6 Radiological Protection and Chemistry Organization and j A d mini stration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 ;

P2 Conduct of Emergency Preparedness Activities . . . . . . . . . . . . 68 P8 Miscellaneous Emergency Preparedness issues . . . . . . . . . . . . . 69 S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . 70 l S8 Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . 71  ;

V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 X1 Exit Meeting Sum m ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 i

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EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/96-09; 336/96-09:423/96-09 Operations

• At Unit 1, spurious downscale alarm on a refueling floor radiation monitor caused the reactor building ventilation system to shutdown and isolate, and the standby gas treatment (SBGT) system to automatically initiate. The performance of the Shift Manager following this event was weak,in that he had not made an appropriate l operability determination prior to resetting the isolation signal. The decision to reset the isolation was based on verbal assurance from an I&C technician after making a visual inspection of the control room indication. (Section U1.01.1)

• At Unit 1, the licensee failed to notify the NRC as soon as practical snd in all cases, within four hours of the occurrence of the event as required by 10 CFR 50.72(b)(2Hi) in five separate instances. The failure to report these issues promptly is an apparent violation. The licensee's implementation of the adverse condition I report (ACR) process and timeline expectations for determining reportability does not provide assurance that reportable events are promptly addressed. Further the failure to address a similar reportability issues resulted in this subsequent violation j and is indicative of the continued ineffective corrective actions. (Section U1.01.2)

• The licensee failed to staff the Millstone Unit 1 Director position, responsible for the safe and efficient operation of the unit, with a qualified ir'dividual. The previous Millstone Unit 1 Director did not have the requisite senior reactor operator (SRO)

level training or experience necessary to fill the position of Unit Director which he held for approximately 15 months. This is an apparent violation of technical specifications. The licensee does not have procedures or written guidelines for the staffing of key nuclear positions. In addition, the licensee did not follow their standard protocols for staffing of nuclear positions, when placing the previous Unit Director in the position, nor was there a documented equivalency determination for it. necessary SRO training and experience. (Section U1.06.1) j i

• The licensee failed to perform a comprehensive evaluation and disposition of

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regulatory requirements to support recent Millstone site organizational change The updated final safety analysis report (UFSAR) reviews performed were narrowly focused and only addressed the new organization reporting responsibilities in the evaluation. In some cases, changes were made contrary to the UFSAR without modifying the requirement. The failure to evaluate and disposition all requirements related to the organizational changes, at all Millstone Units, is unresolved pending the licensees identification and evaluation of these potential non-compliance issue The licensee implemented several organizational changes which resulted in a technical specification non-compliance. This is an violation of technical specifications for all Millstone Units. Although the majority of the deviations are of minor significance the changes demonstrate a continued disregard for regulatory compliance. (Section U1.06.2)

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i e The inspector concluded that the Event Review Team review (ERT) performed in response to the Quality and Assessment Services (OAS) audit findings was narrowly focused and lacked substance. The ERT was performed only to fulfill the requirement to perform an ERT for all significance level 'A' ACR This is an apparent violation of 10 CFR 50, Appendix B, criterion XVI, " Corrective Actions."

This is a concern to the NRC since it illustrates the licensee continued poor performance in thoroughly addressing corrective action issues. (Section U1.07.1)

e The Unit 2 backlog of 940 adverse condition reports (ACRs) that are greater than 120 days old indicates that timeliness for completing corrective actions, particularly l in the design engineering department (609 ACRs), remains a concern. As discussed j in NRC Inspection Report 50-336/96-04, timeliness and effectiveness of corrective l actions is an area in which the licensee must demonstrate sustained improved performance before the NRC will allow the unit to restart. (Section U2.01.2)

l e Given the fact that reportability timeliness has been a longstanding issue at !

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Millstone, performance at Unit 2 was weak in allowing a backlog of 90 reportability i evaluations to develop. As a corrective action, the licensee is developing guidance I for dispositioning reportability evaluations such that the 30-day reporting i requirement of 10 CFR 50.73 is satisfied. The NRC will continue to monitor  !

licensee performance in this area when reviewing licensee event reports. (Section U2.01.3)

e Licensee performance was good in identifying and evaluating the cause of an i inadvertent 1 % inch reduction in Unit 2 spent fuel pool (SFP) level through a SFP i purification pump vent. The safety significance of the event was minimal because i the SFP is designed to prevent a significant amount of draining by placing the I l purification suction line high in the SFP. (Section U2.01.4)

e Although-an NRC information notice informed the licensee of the concern, during .!

the annual emergency preparedness exercise, the operating procedures and j

,' management expectations were not clear regarding when operators may override an l automatic safety injection actuation. This issue is considered unresolved. (Section !

U2.03.1 )

e Overall, the Unit 2 operator requalification program was good in ensuring appropriate program content, development of the wntten examination, and evaluation of operator performance. However, one program weakness was that the simulator examination scenario bank lacked diversity, covering a limited set of I failures. (Section U2.05)

e The Unit 3 licensed operaters and licensee management continue to satisfactorily control shutdown risk in planning and conducting plant evolutions and in l implementing configuration management program activities. Operability l determinations and adverse condition reports appear to be receiving appropriate

management attention to ensure a deliberate approach to the resolution of the

, identified concerns. (Section U3.01.1) Similarly, the licensee's control of  ;

conditions affecting the status of the station safety-related batteries was  !

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temporary modifications. (Section U3.02.1)

Maintenance

• At be n :. aix reactor coolant components had an unacceptable structural integrity l

and a high prdbility of abnormal leakage. These flawed components were placed inservice, between 1984 and 1995, without flaw analysis as required by ASME Section XI. This is an apparent violation of Technical Specification 3.6.F,

" Structural Integrity," which states that the structural integrity of the primary boundary shall be maintained at an acceptable levelin accordance with 10 CFR 50.55a(g). Unresolved item 245/96-06-03 is administrative!y closed in lieu of the apparent violation. (Section U1.M8.1)

• At Unit 2, the NRC found that the licensee's method of verifying that high pressure l

safety injection (HPSI) breakers were racked out did not strictly comply with the technical specification (TS) surveillance requirement. Licensee corrective actions included reviewing other TS surveillances, and found a number of additional strict compliance concerns. Due to the licensee's prompt corrective actions in reviewing other TS, the HPSI TS concern was characterized as a non-cited violatio (U 2.M 1.1 )

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• At Unit 3, with the exception of procedure SP 3712NA, " Battery Surveillance

Testing," all reviewed surveillance procedures appropriately incorporated the requirements of the applicable technical specification. (U3.M1.1)

• Unit 3 management clearly conveyed their standards and expectations, stressed the importance of the maintenance department, and of the need for individuals to accept and effect change to improve the performance of the station. (U3.M1.2)

• Unit 3 maintenance and surveillance activities observed were completed thoroughly, l professionally, and in compliance with all stated criteria. Good procedure adherence was demonstrated during the service water strainer repair. The work package for -

the strainer repair was determined to be adequate for the performance of the jo (U3.M1.3)

• At Unit 3, followup on the delamination of the Arcor coating on the internal diameter of the service water (SW) piping revealed that pieces were large enough that some became wedged in the tubes and others blocked SW flow to the recirculation spray system heat exchangers. A similar concern was also identified at Unit 1. The licensee's original safety evaluation (SE) performed to evaluate the use of the Arcor coating determined that the application of the coating to the SW l piping did not constitute an unreviewed safety question. The SE indicated that the l

adhesion of the coating had been thoroughly tested at an independent laboratory,

! with no loss of adhesion observed. In the event adhesion is not maintained, the i epoxy would chip off and pass through the SW system. This issue is unresolved, pending further review of the licensee's position and actions on this matte (U 3.M 2.1 )

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• Numerous safety-related and non safety-related structures, systems or components l

i for Unit 3 were inappropriately left out of the scope of the maintenance rule (MR),

including fuel assemblies, fuel handling system, alternate shutdown panel, radiation monitoring panel, emergency lighting battery pack support, and the tunnel under the

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Service Building (all safety-related), and fire protection system, post accident sampling system (PASS), seismic monitoring system, communication and emergency lighting. Further, there were 11 additional systems, which included a small percentage of safety-related components, that had been excluded from the maintenance rule scope without documented justification. Both areas above represent unresolved items that will be addressed after further review during the j maintenance rule baseline team inspection. (Section U3.M3.1)

• The inspectors judged the Unit 3 process for risk ranking to be adequate. However,

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the Probabilistic Risk Assessment (PRA) used only generic equipment failure data, and the truncation level was relatively high, allowing the possibility that risk significant equipment was not identified. The safeguards equipment room ventilation and coolers have been excluded from being risk significant without

! completing the room heat load calculations. The licensee did not use containment equipment or external event analysis in quantifying risk ranking of systems. (Section U3.M3.2)

Engineering

• The failure to perform and document a safety evaluation which provides the bases for determining that the changes to the diesel generator starting air system do not involve unreviewed safety questions, is an apparent violation of 10 CFR 50.5 This apparent violation is of concern to the NRC due to the apparent lack of programmatic controls to assure that hardware configuration and functional changes are appropriately reviewed. Further, the licensee's failure to assess these programmatic controls in the seven months since this issue was identified in ACR 10900 demonstrates untimely corrective action. (Section U1.E1.1)

! * In a letter to the NRC, the licensee stated that a change to the licensing basis would close GL 89-13 issues for Millstone Unit No.1, which was not accurate in

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representing that GL 89-13 would be closed following issuance of the requested amendment. Fu ifically, at the end of the inspection period a formal program had not been implernented to address GL 89-13, items 1 or 3 recommended actions. In addition, the licensee had not implemented testing necessary to address GL 89-13,

! item 2. Further, actions associated with item 5 were incomplete, in that, reviews l performed were not appropriately documented neither initially nor after a licensee

internal audit identified documentation discrepancies. This is an apparent violation

of 10 CFR 50.9(a), which requires information provided to the NRC by a licensee to

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be complete and accurate in all material respects. (Section U1.E3.1)

• At Unit 2, the licensee's process for dispositioning known design and licensing basis

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discrepancies that could adverseiy affect Mode 6 operations was effective and no concerns were identified. (Section U2.E1.1)

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• At Unit 2, corrective actions were inadequate to address a significantly flashed main bearing in the B" emergency diesel generator which had signs of overheating due to insufficient lubrication. One month later, again due to insufficient lubrication, the same bearing overheated to the point of melting resulting in significant engine damage. The inadequate corrective action for the flashed bearing was considered I an apparent violation. (Section U2.E2.1)

• The licensee's initial review and follow up of NRC IN 88-24 and GL 91-15 for ,

Millstone Unit 3 were inadequate. A detailed review for potential components 1 affected and of purchase records was not performed to determine the full extent and applicability of the problem. As a result, the safety function of 48 solenoid-operated valves (SOVs) was potentially impacted because of excessive operating pressure differentials. This results from f ailures of the non-qualified air regulators installed in the instrument air system located upstream of the SOVs. The failure of the licensee to establish design controls to verify the adequacy of the design of ASCO SOVs to operate properly when subject to fullinstrument air pressure is an j apparent violation of the requirements of 10 CFR 50, Appendix B, Criterion ill,

" Design Controls." Unresolved item 423/96-08-19 is administrative!y close i (U 3.E2.1 )

e The licensee performed a safety evaluation that allowed the elimination of the procedural requirement to open the emergency diesel generator (EDG) access hatch

n receipt of a tornado alert. The removal of this requirement increases the piubability, although negligible, of a malfunction of the EDG. The NRC considers the deletion of this licensing commitment as a removal of an original design

?equirement and, therefore, NRC concurrence is required. The determination as to

^ ether this issue was properly handled will te reviewed by the NRC for technical !

adaquacy. Continued NRC review of this issue is considered an item for further inspection followup. (U3.E2.2)

e The root cause evaluation for a Unit 3 inadvertent containment depressurization actuation (ACR 1895) signal did not adequately address improper safety taggin l (U3.E2.3)  !

e The Unit 3 engineering assessment of the potential for freezing in the service water strainer blow down piping did not include an adequate technical bases to support the conclusion. (U 3.E 8.1 )

Plant Support

• In a letter to the NRC, the licensee discussed the material condition of the Radwaste Facilities at Millstone. The letter stated that upon determining the degree to which the material conditions had deteriorated, an Adverse Condition Report (ACR) was initiated to document the findings. The ACR was assigned a significance Level B, thus requiring a root cause analysis. Contrary the above statements, the licensee identified that the only level 'B' ACR on this issue was ACR 002372, dated January 18,1996, which documented that the general material condition of the U/1 liquid radwaste facilities were in an unacceptable state. This was one month sfter the viii

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original letter. This is an additional example of the apparent violation of 10 CFR 50.9(a), which requires information provided to the NRC by a licensee to be complete and accurate in all material respects. (Section R2.1)

e The licensee has established a unitized radiation protection program and selected :

qualified personnel to serve as radiation protection managers in each unit. The new i

- organizations reflect a significant increase in management attention towards work control and maintaining occupational exposures as low as is reasonably achievabl (Section RS, R6)

e The licensee's evaluation report for the September 29,1996, call.in drill indicated that ernergency plan commitments were met. (Section P8.1)

e Two areas for improvement noted during the annual emergency preparedness exercise were that: (1) the role of the Shift Technicc-1 Advisor was not well defined; and (2) due to the tirne spent interacting with the emergency response organization, the Shift Manager had a limited amount of time to monitor overall plant conditions and operator actions. (Section P2.1) -

o The inspectors reviewed the event associated with an unauthorized entry into the Millstone Station protected area (PA) by an administrative contract person and documented the results in NRC Inspection Report 50-245/96-06. During this event, an individual failed to comply with the licensee's security requirements and conditions of unescorted access authorization. This is a violation of Millstone Security Plan requirements. (Section S8.1)

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Summarv of Plant Status l

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l Unit 1 remained in an extended outage for the duration of the inspection period. The licensee continues to review the plant's level of compliance with regulatory requirements, and compliance with their established design and licensing basis, associated with an NRC l

request pursuant to 10 CFR 50.54(f) and Confirmatory Order U1.1 Operations ,

l U101 Conduct of Operations l

01.1 General Comments (71707)

Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing j plant c;wations to ensure that licensee's controls were effective in achieving continued :

safe operation of the facility. The inspectors observed that proper control room staffing '

was maintained, access to the control room was properly controlled, and operator behavior l was commensurate with the plant configuration and plant activities in progress. Specific l events and noteworthy observations are detailed in the sections belo :

I 01.1 Refuel Floor Radiation Monitor j l Insoection Scone (71707)

j The inspectors reviewed the event associated with a spurious downscale alarm on a l refueling floor radiation monitor, and assessed the Shift Managers response to the even l l Observations and Findinas l On November 8,1996, a spurious downscale alarm on the refuel floor radiation monitor channel 1 occurred, while a downscale/INOP signal existed on refuel floor radiation monitor '

channel 2. Channel 2 was taken out of service earlier for calibration in accordance with SP 406O " Reactor Building Exhaust Duct and Refuel Floor High Radiation Monitor Functional Test and Calibration." The two downscale trip signals caused the reactor building  ;

ventilation system to shutdown, isolate, and the standby gas treatment (SBGT) system to l automatically initiat l The inspector reviewed the control room logs on the morning of November 8, and noted ,

that the reactor building isolation signal had been reset and the systems restored to normal '

operation, within 45 minutes the spurious downscale isolation. The inspector discussed with the Shift Manuger of his basis for declaring the refuel floor radiation monitor operable

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and resetting the isolation signal. Discussions with the Shift Manager indicated that the l isolation signal was reset based on verbal assurance from an instrumentation and controls l (l&C) technician that the monitor was operable. The l&C technician's assessment was i based on a visual inspection of the control room indicatio The inspector discussed his concern with the lack of an appropriate operability ( determination, with the Shift Manager, who then requested that a more complete I

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operability basis be provided by the I&C department. This assessment was completed, documented, and reviewed by operations, and found acceptabl The channel 1 refuel floor radiation monitor is a group 3 General Electric sensor and converter. This group 3 range detector has a history of high signal fluctuations. The spurious downscale indication on channel 1 were the result of a weakened " bug" source concurrent with signal fluctuations, which had been seen in the past. The channel 1 refuel floor radiation monitor was removed from service and functionally tested and calibrated satisfactorily on November 7,1996. After the monitor was re-installed following :

calibration, with the bug source in position, the monitor was responding to the bug source !

i field and was indicating above the downscale trip point as expected. The pre-calibration and post-calibration radiation levels as indicated on the moritor were compared as required by the procedure to verify that the monitor was properly connected. l&C staff determined l that the monitor would have responded to an actual radiation condition and functioned as )

designe Conclusions A spurious downscale alarm on refuel floor radiation monitor caused the reactor building ventilation system to shutdown, and isolate and the standby gas treatment (SBGT) system to automatically initiate. The reactor building isalation signal had been reset and the systems were restored to normal operation, within 45 minutes of the spurious downscale isolation. The inspector conclude that the performance of the Shift Manager following this event was weak,in that he had not made an appropriate operability determination prior to resetting the isolation signal. The decision to reset the isolation was based on verbal assurance from an l&C technician after making a visual inspection of the control room indicatio .2 Timeliness of Reoortability Assessments Insoection Scoce (92700)

A review of the timeliness of the licensee's reportability evaluations was performed.10 CFR 50.72(b)(2)(i) requires that the licensee notify the NRC as soon as practical and in all cases, within four hours of the occurrence of any event, found while the reactor is shutdown, that, had the it been found while the reactor was in operation, would have resulted in the nuclear power plant, including its principal safety barriers, being seriously degraded or being in an unanalyzed condition that significantly compromises plant safet Observations and Findirigs During this inspection period, a number of Adverse Condition Report (ACR) issues were identified that had not been promptly assessed for reportability. Procedure RP 4, " Adverse Condition Resolution Program" states that if "an ACR requires or potentially requires the submission of a licensee event report (LER) or other written report, ensure investigation assignment due date supports draft report submission within 14 days." Although the ACR process provides the framework for assessing reportability, it does not provide for timely evaluation of issues potentially reportable under 10 CFR 50.7 _ _ _ _

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During the review of prompt reports for timeliness, the inspector identified five events that were not appropriately reporte e ACR 10900, was initiated on April 8,1996 and identified that the diesel air start system check valve internals had been removed without proper evaluation and documentation. However, this issue was not promptly reported until November 22, 1996, as a result of the evaluation of a subsequent ACR, M1-96-0939, which i documented the same issue. In the case of ACR 10900 the shift manager l incorrectly deterrnined that the issue was not reportable, in addition, during the :

review for reportability of a related ACR M1-96-0237, which identified similar )

vulnerabilities in the diesel air start system, the licensee missed a second '

opportunity to report this conditio e ACR M1-96-0237, was initiated on July 15,1996 and identified a condition in which the EDG air receiver would not automatically pressurize following the ;

installation of the internals of the check valves. The ACR indicated that the UFSAR 1 stated that "the two air compressors are started if the pressure in the reservoirs falls to 225 psig and stopped when the pressure in the air receivers reaches 250 psig." The ACR stated that "there is a contradiction between the field condition and the statement, this is because both compressors don't start together, and -

review of the setpoint date shows that the de compressor starts at 220 psig not 225 psig, therefore, a clarification is required." The inspector noted that this design discrepancy was not reported until November 12,1996 in response to a related AC e ACR M196-0715, was initiated on October 23,1996 and identified inadequate testing of the emergency diesel generator air start capability, However, this issue was not promptly repcrted until November 12,199 e ACR M1 96-0798, was initiated on November 6,1996 and identifioc a flooding vulnerability for the condensate pump pit that could jeopardize the shut down method following a tornado. However, this issue was not promptly reported until November 15,1996 e ACR M196-0843 was initiated on November 7,1996 and documented inadequate seismic supports for piping connected to the isolation condenser. However, this issue was not promptly reported until November 13,1996. In this instance the initiator of the ACR failed to promptly process the issu In the first two of the examples above, the ACR's were screened by the shift manager who concluded that reportability was uncertain. The ACRs were then assigned to an individual to evaluate the reportability of the issue along with the assessment of the cause and develop corrective action The inspector had previously discussed similar reporting issues and ACR process vulnerabilities in meeting reporting requirements. For 7.xample, NRC report 245/96-04, section U1.08.3, discussed late 50.73 reports. In addition, on October 9,1996, the licensee initiated ACR M1-96-0668 to address a late prompt report associated with the w - 7

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control rod drive (CRD) seismic qualification as a result of NRC inspection activitie However, the ACR was dispositioned as a level "D" and no corrective action was take This issue was subsequently addressed in NRC report 50-245/96-08. section U1.E In response to the most recent reportability issue, an ACR was initiated to address the cause and corrective actions necessary to ensure prompt reporting of applicable issues. In addition, the new licensee management provided the expectation that all potentially reportable issues be assessed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of dUcovery. The licensee plans to incorporate this expectation into procedure RP 4, curing the next revision which was in progress at the end of the inspection period. The licensee also plans to revise NGP 2.25 to include expectations on timeliness and additional guidance on how to perform reportability

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determinations. The revised procedure will replace the "NU Reporting Guidance on 10 CFR 50.72 and 10 CFR 50.73" bookle Conclusions The licensee failed to notify the NRC as soon as practical and in all cases, within four hours of the occurrence of the event as required by 10 CFR 50.72(b)(2)(i) in five separate instances. The failure to report these issues promptly is an apparent violation (eel 50-245/96-09-01). The licensee's implementation of the ACR process and timeline .

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expectations for determining reportability does not provide assurance that reportable ,

events are promptly addressed. Further, the failure to address a sim;!ar reportability issues {

resulted in this subsequent violation and is indicative of the continued ineffective corrective l action U106 Operations Organization and Administration 06.1 Qualification of the Unit Director I Insoection Scoce (71707)

The inspectors reviewed the method in which the licensee places personnel in key nuclear positions and how qualification for these positions are verified. The Unit Director position was used as the focus of this inspection. The Unit Director is responsible for the safe and efficient operation of the respective unit, and in the absence of the Vice President, Nuclear Operations, may assume overall responsibility for the statio Observations and Findinas Based on interview data, the Station Vice President requested that the personnel department provide resumes of potential candidates for the position of Unit 1 Director, in early 1995. The Station Vice President requested candidates with commercial experience including a previous senior reactor operator license. The Personnel Department used the Nuclear Unit Director position description and gaidance provided by the vice president to l advertise and screen potential candidates. The position description states the " Typical l Requirements (Minimum), Training and Experience, (3) Hold or have held and NRC SRO

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license or possess equivalent."

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The Personnel Department subsquently provide the resumes of candidates meeting the ,

l position description requirements. The Station Vice President then told the personnel department to setup interviews with a number of the candidates including an additional candidate that had been recommended by INPO. The personnel manager noted that the additional candidate did not meet the training and experience originally requested; however, when this was discussed with the vice president, the personnel manager was directed to set up the interview anyway. This person, without the requisite training and experience, was subsequently determined to be the best candidate following a series of interviews. The compensation department was then asked to determine the pay options for an employment offer to this candidate. The compensation staff stated that typically they verify the requisite education and experience; however, in this case they only looked at salary options. Following further discussion with the inspector, the individual performing the compensation review stated that at the Director level, experience and education are not normally challenge The inspector determined that the licensee does not have procedures or written guidelines for the staffing of key nuclear positions. However, the licensee's personnel and compensation staff stated that they follow standard industry protocols for staffing of l nuclear positions. The licensee's personnel staff also stated that typically if a training or experience equivalency determination was necessary, it would be documented to support the hiring decision. However, in the case of the previous Unit Director, there was no equivalency determination for the SRO experience documente Technical Specification 6.3.1, " Facility Staff Qualifications," requires that, "each member of the facility staff shall meet or exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions." ANSI 18.1-1971, " Selection and Training of Nuclear Power I Plant Personnel," section 4.2.1, " Plant Managers," states, the plant manager shall have acquired the experience and training normally required for examination by the Atomic q Energy Commission (AEC) for a Senior Reactor Operator's license whether or not the t l examination is taken. The Unit Director position at Millstone is equivalent to the Plent Manager position referenced by the ANSI standar The UFSAR, section 13.1.2.2.1, " Plant Positions and Descriptions," em 2. " Director, !

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Nuclear Unit," states the following, "(c) must hold or have held a Senior Raactor Operator's (SRO) License on the respective unit or possess knowledge equivalent to that required to obtain an SRO License."

The licensee's initial position was that the previcus Unit Director was qualified, but the training provided following his selection for the position may not have been adequate. As a result, the licensee generated an adverta condition report (ACR). The training program provided was a one week familiarization on the safety-related systems and design features for a Boiling Water Reactor (BWR) but did not include objectives or an evaluation. The licensee's bases'for their position was that the Navy nuclear program has been accepted as a bases for the qualification of individuals for the commercial nuclear program by the AEC and the Nuclear Regulatory Commission for the past 25 years. Further, that the previous Unit Director was qualified as an Engineering Officer of the Watch which is equivalent to an administrative Senior Reactor Operator licens !

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! 6 l Following a discussion with inspector, the licensee determined that the bases for their

! position was inappropriate. Subsequently, a OA surveillance MP1-P-96-037 documented i - that there is no documented evidence that the previous Millstone Unit 1 Director met the requirement to possess knowledge equivalent to that required to obtain an SRO license. A 1 second ACR was initiated to address this issu Subsequently, the licensee has determined this issue is reportable and plans to docket a j licensee event report as required. The licensee also plans to have QA perform an audit of l the qualifics' ion of all management at the Millstone site. A review of the decisions and correspondence issued by the previous Unit Director will be performed, however, at the end of the inspection period the criteria had not been established, in addition, the second l ACR initiated was assigned a significance level "B" which requires a root cause evaluation.

l The licensee plans develop appropriate corrective actions including the process for l

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placement cf personnel in key positions based on the root cause evaluations finding Conclusions l

The licensee failed to staff the Millstone Unit 1 Director position, responsible for the safe and efficient operation of the unit, with a qualified individual. Specifically, the technical specification requires that each member of the facility staff shall meet or exceed the l minimum qualifications of ANSI N18.1-1971, which in turn states, the plant manager shall l have acquired the experience and training normally required for a Senior Reactor Operator's license. The previous Millstone Unit 1 Director did not have the requisite SRO level of l training or experience necessary to fill the position of Unit Director which he held for approximately 15 months. This is an apparent violation (eel 50-245/96-09-02).

The licensee does not have procedures or written guidelines for the staffing of key nuclear l positions. In addition, the licensee did not follow their standard protocols for staffing of.

l nuclear positions, when placing the previous Unit Director in the position, nor was there a l

documented equivalency determination for the necessary SRO training and experience.

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06.2 Imolementation of Oroanizational Chances l

l Insoection Scope (71707)

The inspectors reviewed the licensee's evaluations of Technical Specifications, the UFSAR, the Emergency Plan, the Security Plan, and the QA topical report performed to support the implementation of recent organizational change Observations and Findinos On October 3,1996 the licensee forwarded letter B15922 to the NRC, which described changes to the Northeast Utilities organization effective October 1,1996. This letter i provided the revised organizational charts and rationale for the changes. In addition, the i

letter withdrew a pending technical specification amendment request (TSAR) to revise Technical Specification (TS) section 6 in support of previous organizational change Further, the letter stated that the licensee would request a change to the technical

specifications to reflect the newly announced organization in the near future.

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On October 21,1996 the Unit 1 organization, as described in the licensee's October 3, l 1996 letter, was changed again, in this revision, the licensee eliminated the position of l

Unit Director and established four separate director level positions to fulfill the I responsibilities previously filled by the Unit Director. This in effect put the Unit Director responsibilities into four functional areas with a director assigned to each area. This l organization also includes a director of engineering similar to the previous organization, however, during the October 1,1996, reorganization, the engineering director's position reporting relationship was changed such that this position now reports to the responsible ,

recovery office l in an October 21,1996, memorandum from the Unit 1 Recovery Officer to the Operations Director, the responsibikties of the Unit Director as delineated in section 6.0 of Technical Specifications and other references, were assigned to the Operations Director. However, the memorandum excluded PORC, SORC and emergency plan duties, which would remain  !

with Operations Manager until the specific qualifications for each of these duties could be completed by the newly appointed Operations Director.

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Following the announcement of the new Unit 1 organization, the inspectors questioned l what reviews were performed to ensure that the new organization did not reduce previous l

licensee commitments. In particular, the inspectors questioned how the Operations l l , Director could fulfill the responsibility of Unit Director since he was not qualified or fulfilling the position of PORC chairmen as required by the UFSAR. The licensee had not performed

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any comparisons or evaluations of the effect of the new organization on previous ( commitments prior to implementation of the change In response to the inspectors questions, the licensee performed a review of the Millstone Quality Assurance Program and Topical Report in accordance with 10 CFR 50.54(a) several days after the change was implemented. This review considered the OA topical report, the UFSAR, Technical Specifications and included a safety review. The analysis concluded that the reorganization at Millstone 1 does not reduce the level of commitments in the QA program or any other commitments previously made to the NRC. The licensee initiated ACR M1-96-1098 to address the failure to perform the 50.54(a) review in a timely manne On October 22,1996, the Vice President of Nuclear Oversight issued memorandum DMG-96 017, "Recent Changes involving Unit One," to the Unit 1 Recovery Officer. The memorandum stated "it is not clear that these changes have been made in light of Unit One's Technical Specifications and approved programs and procedures, and that any subsequent impacts have been addressed and properly resolved." The memorandum also discussed number of examples of TS section 6 and other program issues, and then questioned regulatory compliance in light of the recent changes. The inspector determined l that in general these issues were not resolved nor did the Oversight Department follow-up l to assure proper resolution of these issue The inspector reviewed the 50.54(a) analysis performed for the October 1,1996 change i and found that it also addressed the QA topical report, and the UFSAR, but did not.

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specifically address technical specifications. However, the conclusion states, "that the new reporting responsibilities, including oversight activities as described in the FSAR, Technical Specifications and the Topical Report will not reduce the level of commitments l

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nor result in any unreviewed safety questions or concern." This review also recognizes the need to revise the UFSAR to reflect the organizational change Technical Specification cection 6 delineates the lines of authority and levels of responsibility for various programs and administrative functions. The organizational changes implemented introduced discrepancies between the titles of the new organization and the organization as described in technical specifications. For most functions affected by the changes, the organizational level of the individual assuming responsibility was equivalent or higher than that previously reviewed and approved by the NRC. However, in a number of cases the organizational level of the individual assuming responsibility was decreased. For example, functions, as described in technical specifications, which were the responsibility of the Executive Vice President have now been assigned to the applicablo Recovery Officer. The functions include:

6.5.1. Receives report on violations of Technical Specifications from PORC; 6.5.1. Receives notification of disagreement between PORC and the Unit Director; 6.6. Receives copy of PORC review of reportable events; 6.7. Notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of any reportable event; 6.7. Notified within 14 days of a safety limit violatio In addition, the licensee has assigned the Nuclear Engineering & Support Recovery Officer as the SORC chairman, contrary to Technical Specification 6.5.2.2, which requires the Senior Vice President to be the SORC chairman. As a result of the inspection, the licensee initiated ACR M1-96-0810, to address the changes made to the Unit 1 organization that constitute a deviation from section 6 of the technical specification At the time of the inspection and with the licensee's recognition that they were currently in non-compliance with technical specifications, the licensee committed to submit the necessary technical specification amendment request by November 22,1996. However, continued organizational responsibility changes and delays in the Unit 2 reviews of the amendment request caused this and several subsequent commitments to be misse Following a discussion between senior NRC managers and the licensee, the amendment request was submitted to the NRC on December 24,1996. However, at the end of the inspection period the NRC had not acted on the request and thus the licensee remained in non-complianc '

As a result of the ongoing non-conformance and delays in processirg ihe technical specification amendment request, the licensee initiated another ACR M1-96-1098 to address the programmatic weaknesses in the process for implementing organizational changes. In addition the licensee plans to docket an informational licensee event report to l document this issu The inspector noted that the Emergency Plan 10 CFR 50.54(q) " Decrease in E4fectiveness Review," for the October 1,1996, change was completed one week after the change was implemented; however, this review did not identify a decrease in emergeacy plan effectiveness. Further, no 50.54(q) review was performed in supocit of the October 21, 1996 change. The licensee did not provide the requested evaltations of the security plan tnat were performed to support the organizatioral changes, by the end of the inspection perio .-

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Subsequent to the inspection activities discussed above, the licensee initiated an adverse condition repon @CR), M1-96-0968, to address the organizational changes made to chemistry and health physics without performing the appropriata reviews and documentation. The ACR references the October 1,1996 chaga and indicates that not all organizational changes were addressed by the previous reviews to support this chang At the end of the inspection period, the licensee determined that a comprehensive review of all applicable requirement had not been performed to support either of the two organizational changes discussed above. The licensee plans to establish a matrix of existing requirements related to the organizational structure and responsibilities. The licensee will then perform a review of the organizational changes made and resolve any discrepancies identified. The licensee expects to complete this review by January 24, 1997. The licensee also plans to complete a root cause evaluation for the TS section 6 non-compliance and implement appropriate corrective actions to address the causes in the near term. In the interim, the President and CEO willissue a memorandum prohibiting further organizational changes until actions have been implemented to prevent reoccurrance of this issu Conclusion The licensee failed to perform a comprehensive evaluation and disposition of regulatory requirements to support a recent Millstone site and a subsequent Millstone Unit 1 organizational changes. The Unit 1 line organization subsequently failed to address a number of potential regulatory non-compliance questions from the oversight organizatio In addition, the oversight organization failed to followup and assure proper resolution of l these issue I l The UFSAR reviews performed were narrowly focused and or4y addressed the new i organization reporting responsibilities in the evaluation, in some cases, changes were made cutrary to the UFSAR without modifying the requirement. For example, following implemerration of the October 21,1996, organization, the Operations Director was not the PORC charman as required by the UFSAR. In addition, the Station Vice President is required to approve all station administrative procedures, however this position was ;

eliminated dering the October 1,1996, reorganizatio The failure to t valuate and disposition all requirements related to the organizational changes. at all Millstone Units, is unresolved (URI 50-245/336/423/96-09-03) pending the licensees identification and evaluation of these potential non-compliance issue The licensee implemented several organizational changes which resulted in a technical specification non-compliance. In addition, for the Unit 1 specific change, the licensee used a memorandum to modify the responsibilities delineated in technical specifications. This is a violation (VIO 50-245/336/423/96-09-04) for all Millstone Units. Although the majority of the deviations are of minor significance the changes demonstrate a continued disregard for regulatory complianc The licensee's 50.54a reviews for the October 1,1996, and the October 21,1996, organizational changes were not completed until several days after the organizational l

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changes were implemented. In addition, the 50.54(a) review for the October 21,1996,

change was prompted by the NRC.

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l U107 Quality Assurance in Operations

i ( 07.1 Quality Assurance Services Adverse Condition Reoort Audit I 1 j Insoection Scooe (40500)

! In NRC Inspection Report 50-245/96-05, the inspectors reviewed the findings of a Quality l Assurance Services (QAS) audit of the Adverse Condition Report (ACR) process. The results of the audit indicated that there continued to be an inadequate implementation of the corrective action program. In response to the audit, the !icensee initiated ACR 13318 on May 10,1996. During this inspection period, the inspector reviewed the root cause analysis and corrective actions following the completion of the ACR review.

! Observations and Findinas

The results of the OAS audit determined that causal factors were not being established,

. which resulted in a failure to provide actions to prevent recurrence. QAS also questioned the effectiveness of the management review process for completed ACRs, since problems were identified in ACRs that had received a management review. Additionally, the i effectiveness of corrective actions were not being evaluated for ACRs. As a follow-up to l this audit, QAS initiated a significance level "A" ACR, which required an ERT to assess l l these findings. The inspector reviewed a memorandum, dated May 21,1996, which  !

l stated: "This memo establishes an ERT to evaluate ACR 13318, which concluded that the 1 ACR corrective actions process is not being effectively implemented. The ERT's charter is _,

to determine the underlying causes of the deficiencies documented in ACR 13318 and  !

recommend any appropriate corrective actions above and beyond the five-unit common ACR process planned for implementation prior to Millstone Unit 3 restart." The eleven findings documented in ACR 13318 were provide in the memorandum for the ERT.

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'I l The inspector reviewed the results of the ERT and discovered that the ERT only addrensd l one of the OAS audit findings concerning causal factors not being properly establisned, l

The ERT report scope stated: "A review of all the audit findings by the ACR event review team concluded that only Finding 1 warranted a formal root cause. This report w ll focus

on Finding 1 only. The remaining findings are addressed in ACR 13318 Form RP4-7 "ACR l Causal Factor Corrective Action Plan." The Director-Nuclear Operational Standards was briefed and agreed with this conclusion." The other findings were assigned and

, dispositioned as significance level "D", which do not require causal factors or root cause analysis to be performe In the report's conclusion, the ERT stated: "The ERT reviewed all the " whys" with respect to the broken management review and weak causal factor determinations. This was a

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unique approach to the root cause evaluation in that a barrier analysis was performed with the various casuals being evaluated against the current corrective action plan for the ACR process. While there are many potential reasons, such as lack of knowledge, lack of training, lack of proper expectations, the implementation of the MRT [ Management Review l

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Team] will provide the peer review and coaching necessary to ensure that all credible causal factors are addressed."

The ERT concluded that implementation of the MRT end assoc;ated review of ACR investigation results and corrective action plans would provide an effective peer revie Additionally, the inspector noted that no additional corrective actions or recommendations above and beyond the Nuclear Excellence Plan were made by the ER The inspector's concerns with the adequacy of the ERT report were discussed with the licensee. On November 11,1996, the licensee initiated ACR M1-96-0823, which documented the ineffective corrective actions for ACR 13318 that included a root cause report, causal factors, and corrective action plan that took credit for a draft Operating Experience Manual (OEM) as part of the Nuclear Excellence Plan. This plan was not implemented, and therefore corrective actions identified were not implemente _Q_onclusions The inspector concluded that the ERT performed in response to the QAS audit findings was narrowly focused and lacked substance. Following discussions with the licensee's staff the inspector concluded that the ERT was performed only to fulfill the requirement to *

perform an ERT for all significance level "A" ACR. The failure to take corrective action is an apparent violation (eel 50-245/96-09-05) of 10 CFR 50, Appendix B, criterion XVI,

" Corrective Actions." This is a concern to the NRC since it illustrates the licensee continued poor performance in thoroughly addressing corrective action issue U1.11 Maintenance U1 M1 Conduct of Maintenance M 1.1 Steam Tunnel Ventilation Radiation Monitor Insoection Scooe (61726)

The inspectors reviewed issues associated with the performance of SP 406W, " Steam Tunnel Ventilation Radiation Monitor Functional Test and Calibration." Observation and Findina On November 26,1996, during performance of SP 406W it was discovered that the downscale trip functions for both steam tunnel ventilation radiation monitors did not trip as required by design. The downscale trip function actuates when the detector signal falls below the low level trip point. A downscale on both monitors concurrently, willisolate the l reactor building and steam tunnel ventilation and start the standby gas treatment system.

l This provides a fai! safe action for failures such as loss of detector high voltage or signa Technical specifications do not require a down scale trip nor specify a setpoint for the downscale trip.

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12 The licensee initiated ACR M1-96-0963, documenting this issue and performed a root

cause evaluation. The cause of the event was attributed to a procedural deficiency which

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required adjusting the monitor's downscale trip points with little margin for drift between i the trip points and the signal failure point. This could result in the monitor not detecting a I downscale failure if the setpoint drift Conclusions The inspector reviewed the root cause evaluation and observed the performance of the functional test following the calibration of the trip setpoints, with no deficiencies identifie The licensee plans to change the procedure to adjust the downscale trip point to a value

! sufficiently above the meter zero so that an adequate margin exists. As stated the licensee event report (LER 96-063-00) documenting this event, the procedure update and setpoint change will be completed by March 14,1997, as weil as a review of all Millstone Unit 1 i i radiation monitors for any similar procedural deficiencie U1 M8 Miscellaneous Maintenance issues l

M 8.1 (Closed) URI 50-245/96-06-03: ISI Proaram Review Insoection Scope An inspection was performed to review the licensee's commitment to Generic Letter 88-01

• for the augmented, ultrasonic (UT) inspection program and documented that review in NRC :l Inspection Report 50-245/96-0 Observations and Findinas

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, As a result of that inspection, the inspector was concerned about six reactor coolant i components, (RCAJ-2, RCBJ-1 A, RRJJ-4, RREJ-4, RRCJ-4 and CUBJ-18) with flaws that ,

! were placed inservice, between 1984 and 1995, without flaw analysis as required by I ASME Section XI,1986 Edition, (Paragraph IWB-3640). The six components were ultrasonically (UT) inspected between 1984 and 1994. During the UT examinations, each l component had at least one intergranular stress-corrosion cracking (IGSCC) indication. The ASME Section XI analysis was not performed on the components becausa the UT Level til l

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inappropriately evaluated the IGSCC indications to be geometr The licor see performed an evaluation during the November 1995 refueling outage, RFO 15, in accordance with ASME Section XI,1986 Edition, to determine the operability of the l components and determined the components did not meet the requirements for continued

! service and declared the components inoperable, due to a decrease or elimination of the operating safety margin for structural integrity. The safety margin is decreased when a crack through wall dimension in the component is equal to or greater than 75% of the pipe wall nominal thickness. In this case, the six components had intergranular stress corrosion

- cracks that were greater than 75% through wall. Two of the six components leaked

during preparation for weld overlay.

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_The inspector concluded that the six components had an unacceptable level of structural integrity and a high probability of abnormal leakage. This is an apparent violation (eel 50-

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245/96-09-06) of Technical Specification 3.6.F, " Structural Integrity," which states that ,i

! the structural integrity of the primary boundary shall be maintained as specified in '

Technical Specification 3.13 " Inservice Inspection." TS 3.13 states that the structural ( irRegrity of ASME Code Class 1,2, and 3 equivalent cor. ponents shall be maintained at an l acceptable level in accordance with 10 CFR 50.55a(g). 10 CFR 50.55a(g)(4) requires, that ASME Code Class 1,2, and 3 components meet the requirements in ASME Code,Section XI. ASME Code,Section XI, requires that unacceptable flaws be evaluated per Paragraph IWB-364 Additionally, three programmatic weakness were identified by the inspector and )

documented in NRC Inspection Report 50-245/96-06 and associated with unresolved item  !

, 50-245/96'16-03. These weaknesses included: (1) the IGSCC program does not specify a methodology to cduate unresolved UT indications (UIR's); (2) the examination procedure and calibration blocks for the UT exeminations are not specified; and (3) the IGSCC program does not provide guidelines for tracking and trending UT indications. These

, weaknr ss could result in flawed ccmponents being returned to service without engineering l evaluation, and should be addressed in the response to the violation stated above. URI 50- l l 245/96-06-03 is closed in lieu of the apparent violatio l l

U1.Ill Enoineerina U1 E1 Conduct of Engineering E Diesel Generator Startina Air Svstem Inspection Scoos (37551)  !

The inspector performed a review of adverse condition reports (ACRs) and licensee event reports (LERs) related to the diesel generator starting air system. The ACRs and LERs addressed: 1) the removal of check valve intervals from check valves on the discharge line of each starting air receiver tank; 2) surveillance testing and operation that was not consistent with the design basis for the air start system; and 3) an unplanned automatic start of the diesel generator as a result of surveillance testing, Observations and Findinas During a design bases review, the licensee identified that the emergency diesel generator (EDG) air start check valve internals were removed without a design change.1-DGSA-18A and 18B are check valves on the discharge lines for each of two starting air receivers. The lines tie together and form a common line to the EDG. The valves were indicated on the P&lD and the operations valve lineup, however, an isometric drawing, " Diesel Generator l

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Starting Air Piping From Receiver Tanks M8-81 A/B to Diesel Skid," indicated in Note 1 that the check valve internals were removed with no check function provided. A review of documentation indicated that in 1991, both check valves were disassembled for gasket t

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l repair work and at that time, the internals were found to have been removed. The work orders dated February 14,1991, stated that the check valves were reassembled with new gaskets and that engineering was doing an evaluation for the missing internals. In work '

orders dated June 25,1991, documentation stated " Internals missing from check valve Engineering determined that the check valve internals could hamper the air flow. The valve l was disassembled recently on another automated work order (AWO) when this i determination was made. A review of design documentation could not identify a design I change or engineering evaluation to justify the removal of the check valve internal The condition was documented in ACR 10900, dated April 8,1996, and at that time, it -

was not reported to the NRC since the EDG starting air system was thought to be operable. The ACR stated in the comments section of the shift manager review that "D/G

! starting air is operable, a leak in one tank would be the same as getting a leak in the line

! going to the D/G." The issue of the failure to report this condition is addressed in section U1.01.2 of this report. The inspector reviewed the causal factors and corrective action i i plan for this ACR. While the ACR corrective actions included re-installing the check valve I

! internals, it also acknowledged the f act that with the check valves installed, a leak could

. cause an air receiver to depressurize without starting the air compressor or annunciating j the alarm. This could occur since the low air pressure switch and sensing line are down

! stream of the check valves. The ACR stated that a better design would be to monitor the l pressure in the air receivers as opposed to the air headers, however, the likelihood of

!' incurring a significant air leak without it being identified was considered very small. At l that time, the licensee determined that a design change to modify the sensing location for )

the compressor and alarm pressure switches was not warrante I

! On July 15,1996, ACR M1-96-0237 documented a condition in which the EDG air receiver M8-81 A would not automatically pressurize following the installation of the internals of the check valve. This issue was not reported for similar reasons discussed in l ACR 10900, although the reportability determination for this ACR noted the UFSAR stated that "each air receiver is capable of a minimum of three independent cold diesel engine starts without recharge." This was another opportunity for the licensee to identify that with the check valve internals removed, they were not meeting the design basis for the

, system. Additionally, the causal factors and corrective action plan for this ACR indicated

! that the UFSAR stated that "the two air compressors are started if the pressure in the reservoirs falls to 225 psig and stopped when the pressure in the air receivers reaches 250 psig." The ACR stated that "there is a contradiction between the field condition and the l statement, this is because both compressors don't start together, and review of the l setpoint data show that the dc compressor starts at 220 psig not 225 psig, therefore, a l clarification is required." The inspector noted that this design discrepancy was not l reported until November 12,1996, in response to a related ACR (M1-96-0827), see section U1.01.2 of this report, which addressed the failure to report this condition.

! Also reported on November 12, was the fact that the original FSAR stated that the starting l l air pressure is 250 psig and that each air receiver contained sufficient inventory to start !

i the diesel three times without recharging. This was successfully demonstrated in the

preoperational test by performing three starts at 250 psig. However, no supporting

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documentation was found that provided reasonable assurance that the receivers would

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contain sufficient inventory for three starts when the air receiver pressure is as low as 220

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r psig. The subsequent corrective actions for ACR M1-96-0237 included the development l of an engineering work request for design engineering to relocate the sensing point to the

air receivers, and for the 50.54(f) resolution team to track the design discrepancy with the

' 1 dc compressor starting between 215 and 220 psi On September 23,1996, surveillance procedure SP 668.1, " Diesel Generator Operational

! Readiness Demonstration," was changed to incorporate an alternate method of verifying the EDG air compressor's automatic start logic. The alternate method was to vent the air header from the petcock valve located in the control air line downstream of the check valves. The air was vented through this valve until the compressor start setpoint is l reached and the stcrt of the air compressor was verified. The original method of testing l l the EDG air compressor start logic was by venting the air receivers through the air receiver drain valves 1-DGSA-15A or 1-DGSA-15B. Re-installing the check valve internals isolated l

the receivers from the pressure switch and the receiver drain valve could no longer be used to vent the air heade ,

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On November 12,1996, the EDG inadvertently started while performing the surveillance

. on the diesel generator air compressor's start logic, in accordance with procedure SP l

668.1. The air was vented through a small petcock drain valve on a filter. The petcock l

valve was inadvertently unscrewed from its housing in lieu of being opened. This allowed l l the pressure in the control air line to vent quickly causing the air start valve to open and l l the diesel generator to automatically start. Venting through the petcock valves increased j the probability of an inadvertent diesel generator start,'since the petcock valves vented the i control air line which has a small air volume. However, the revised surveillance procedure did not provide any precautions to the operator concerning the inadvertent start of the diesel generator, as a result of rapidly depressurizing the lin l l During a review on November 22,1996, of ACR M1-96-0827, which documented the EDG H automatic start, the system manager determined that the UFSAR stated that "the two dual air receivers are each capable of a minimum of three independent cold diesel engine starts l without recharging." Without the check valve internals, the air start receivers do not have ,

l independent starts. This issue was previously addressed on ACR 10900, at which time j the significance of reportability and operability were not properly addressed. The condition l was reported on November 22, in accordance with 10 CFR 50.72 (b)(1)(B), being outside

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design basis.

l , Conclusions The failure to perform and document a safety evaluation which provides the bases for determining that the changes to the staring air system do not involve unreviewed safety questions, and can be implemented without prior NRC approval, is an apparent violation (eel 50-245/96-09-07) of 10 CFR 50.59. This apparent violation is of concern to the NRC due to the apparent lack of programmatic controls to assure that hardware configuration and functional changes are appropriately reviewed. Further, the licensee's failure to assess these programmatic controls in the seven months since this issue was identified in ACR

10900 demonstrates untimely corrective action.

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U1 E3 Engineering Procedures and Documentation +

E Inaccurate Corresoondence < Inspection Scone l

Generic Letter (GL) 89-13, " Service Water System Problems Affecting Safety-Related l Equipment," was issued in' July 1989, At that time, operating experience and studies had l led the NRC to question the compliance of the service water system with existing I requirements. The generic letter requested that the licensee perform a number of activities -

to ensure the adequacy of open cycle service water systems. The generic letter also requested that the licensees supply information about their service water systems to assure compliance and confirm that the safety functions of the systems could be accomplished. The inspector reviewed the licensee's actions to address Generic Letter (GL) 89-13. The five actions (items 1 to 5) requested by the generic letter are discussed j separately in the subsections listed below, i Observations and Findinas item 1 GL 89-13 requested, "for open-cycle service water systems, implement and maintain an ongoing program of surveillance and control techniques to significantly reduce the "

incidence of flow blockage problems as a result of biofouling." Enclosure 1 to GL 89-13 recommended a surveillance and control program which included: the intake structure should be visually inspected, once per refueling cycle, for macroscopic biological fouling organisms by divers or by dewatering; continuous chlorination of service water whenever the potential for a macroscopic biological fouling species exists; and redundant and- 4

'-infrequently used cooling loops should be flushed and flow tested periodically at the' ~.

maximum design flow. Other components should be tested on a regular schedule to insure they are not clogged. Loops should be chlorinated before lay-up.

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The licensees response A08201, dated 1/25/90, Attachment 2 stated, "The following program is either in effect or will be implernented."

l l The bays of the intake structure are inspected regularly once per refueling cycle.

l This inspection is performed either by divers or by dewatering the bays of the intake l structure. Based on the program presently in place, the intent of GL 89-13 is met.

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' Millstone Unit No.1 service water system is continuously chlorinated whenever the I potential for macroscopic biofouling species exist I There are two loops that may fall under the criterion " infrequently used" as defined

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i in GL 89-13. They are the emergency service water (ESW) and the diesel generator

supply loop l i

j in two subsequent letters, the licensee again re-affirmed their position that GL 89-13, item

1 was complete. In a letter B13959, dated 4/3/92, and letter B14938, dated 9/13/94, the

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licensee stated "with respect to item 1, "that the program to reduce flow blockage

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problems from biofouling was in place and no further action is required."

The activities described by the licensee generally resembled the actions recommended by the GL enclosure. However, the licensee did not develop a formal program to assure continued implementation of the actions specified in the licensees correspondence. For :

example, the licensees correspondence indicated that the service water system is continuously chlorinated whenever the potential for macroscopic biofouling species exists.

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However, at the end of the inspection period, the licensee had not developed a scheduled time of year to perform hypochlorite outages or contingencies for system failures. Further, the licensees response was incomplete in that it only addressed redundant and infrequently used cooling loops and not other components which should be tested on a regular schedule to insure they are not clogged. The licensee also did not address that cooling loops should be chlorinated before lay-u !

Ite.m 2  !

GL 89-13 requested that licensees " conduct a test program to verify the heat transfer

. capability of all safety-related heat exchangers cooled by service water. The total test

. program should consist of an initial test program and a periodic retest program, in letter B13959, dated 4/3/92, the licensee stated "NNECO hereby confirms that ter,ang l and activities related to items 2,3, and 5 as identified in reference (2) were accomulished on schedule during the 1991 refueling outage. Attachment 1 summarizes those activities >

and testing completed." The attachment identified for water to water heat exchangers that

"if the results of the design review (GL 89-13, item 4) indicates the current criteria for-specifying heat exchanger maint,enance frequency under normal operating loads does not support design basis accident heat loads, revised criteria will be established. : Additional-testing to support the licensing basis will be performed." The attachment also identified-for the low pressure coolant injection heat exchangers that "no heat transfer analysis will be performed on these heat exchangers as no heat load is available at any time during plant operations." However, the next sentence states that additional testing to support the licensing basis will be performed. A similar statement is made for the emergency diesel generator heat exchange The licensees position was re-affirmed in letter B14938, dated 9/13/94 indicating, " by letter dated April 3,1992, NNECO documented that testing and activities related to items 2,3, and 5 were accomplished on schedule during the 1991 refueling outage."

The licensee was inaccurate in representing that testing activities related to item 2 were completed on schedule during the 1991 refueling outage, when severalissues required resolution pending the outcome of item 4. In addition, in the attached details the licensee

discussed the need for additional testing in support of item 4.

l item 3

, GL 89-13 requested that the licensee " ensure by establishing a routine inspection and l maintenance program for open-cycle service water system piping and components that I

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corrosion, erosion, protective coating failure, sitting, and biofouling cannot degrade the performance of the safety-related systems supplied by service water."

The licensee's response, A08201, dated 1/25/90, Attachment 2 stated "although Millstone-Unit No.1 does not have a formal program for the inspection of service water system piping and components, NNECO had informally inspected the service water piping and l l components since the start of plant operation. In addition, inspections are performed when

, there are indications of deteriorated conditions. Millstone Unit No.1 will establish a formal program for the inspection prior to the next refueling outage and the program will be implemented at the time. This program will be based on inspections of generic trouble :

areas and random sampling of other sections of the system." l l l In letter 813959, dated 4/3/92, the licensee stated "an inspection program which meets l the reluirements of GL 89-13 has been established. This program performs inspections for )

, corrosion, erosion, protective coating failure, silting, and biofouling. Based on the results l of these inspections, maintenance is performed."

l On October 2,1992, the licensee reported to the NRC that an engineering evaluation concluded that areas of thinned service water and emergency service water piping discovered during the July / August 1992 outage would not have been able to meet design los<js imposed by a safe shutdown earthquake. Subsequently, NRC inspection report 50-245/92-25 stated that "the degraded areas of SW and ESW had experienced corrosion when the piping exterior protective coating worc off. The pipe walls were further thinned during restoration of the rusty areas without esaluation of the effect of the thinning on system stress analyses."

l In response to the inspection issue, the licensee stated in letter 814414, dated 3/29/93, they " initiated an internal commitment to develop a comprehensive SW/ESW system maintenance and inspection strategy by the end of 1993." The letter later states "that the SW and ESW system inspection / replacement strategy was approved on February 26, 1993. The strategy is a living document and is based on the knowledge of the systems which currently exists."

In letter B14938, dated 9/13/94, the licensee stated "by letter dated April 3,1992,

, NNECO documented that testing and activities related to items 2,3, and 5 were

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accomplished on schedule during the 1991 refueling outage."

The licensee was inaccurate in representing that a formal program was in place to address item 3 requested actions, when no program existe Item 4

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GL 89-13 requested that the licensees " confirm that the service water system will perform its intended function in accordance with the licensing bases for the plant. This i confirmation should include a review of the ability to perform required safety functions in the event of failure of a single active component. To ensure that the as-built system is in

accordance with the appropriate licensing basis documentation, this confirmation should include recent (within the past 2 years) system walkdown inspections."

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in letter B15801, dated 4/18/95, which forwarded a license amendment, the licensee

stated that "this change to the licensing basis would close GL 89-13 issues for Millstone l Unit No.1, and provide the basis for withdrawing the proposed technical specification l revision that relaxes the provision to maintain positive differential pressure in the low i pressure coolant injection heat exchanger."

l Letter B15188, dated 5/11/95, indicated "as stated in the October 3,1994, ISAP submittal, NNECO has submitted closure documentation for the service water system. On l April 18,1995, NNECO submitted a license amendment request which would allow the use of the ANSI /ANS 5.1-1979 decay heat model for calculating suppression chamber ( temperature. This, more accurate model, predicts lower peak suppression chamber temperatures. Approval cf this model is necessary for completion of the remaining GL 89-13, item IV issues for the emergency service water system." The requested amendment was subsequently approved and issued by the NRC on July 24,199 On July 27,1995, the NRC issued a memorandum to file which documented that the April 18,1995, proposed license amendment had been approved and that the licensee had completed the GL 89-13 action item Item 5 GL 89-13 requested that the licensees " confirm that maintenance practices, operating and emergency procedures, and training that involves the service water system are adequate to ensure that all safety related equipment cooled by service water systems will function as -)

intended and that operator of this equipment will perform effectively." in letter B13959, dated 4/3/92, the licensee stated "NNECO hereby confirms that testing and activities

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related to items 2,3, and 5 as identified in reference (2) were accomplished on schedule during the 1991 refueling outage." Subsequently, a licensee intemal audit team was unable to verify the existence of documentation that the necessary reviews were -

conducted. In letter B14581, dated August 16,1993, the licensee stated, "in response to the audit team's concern, all appropriate procedures were subsequently reviewed and found to have sufficient direction to ensure that plant personnel will effectively maintain, repair, and operate the service water system."

The inspector reviewed the licensees resolution of the audit finding. The line organization responded stating that the procedures related to service waty operaticq and maintenance had recently been reviewed, and that the procedures reviewed will be arsembled and retained in the service water system engineer files. However, the only documentation that

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existed was a list of procedures with no reference to the reviews performed, the specific l revisions reviewed, criteria used, or reference to the audit finding. Following the audit, the licensee attached a list of service water procedures to the audit (inding response.

l The licensee was incomplete in the actions associated with item 5, in that, reviews performed were not appropriately documented neither initially nor after a licensee internal audit identified documentation discrepancie ,

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20 l Corrective action

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Following discussions with the inspector, the licensee concluded no formal programs are in {

place to address GL 89-13. The bases for not performing heat exchanger testing were

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i flawed in that, the licensee assumed that the safety related heat exchangers had ample margin, when in fact they did not. The licensee concluded that they were not complete I and accurate relative to GL-89-1 The licensee has performed a sampling review of other similar correspondence and identified additional discrepancies. The licensee plans to perform a root cause evaluation of the incomplete or inaccurate correspondence and willinclude all examples identified to date. The licensee also plans to perform a review the 1994 self assessment related to inaccurate correspondence to determine if the recommendations have been implemented l and were effective or what additional action may be required. The licensee will assa?s what further actions are required, including document review expansions, based ;s ;

determined from the planned and ongoing assessment ! Conclusions In letter 815801, dated 4/18/95, the licensee stated that a change to the licensing basis l would close GL 89-13 issues for Millstone Unit No.1, which was not accurate in representing that GL 89-13 would be closed following issuance of the requested amendment. Specifically, at the end of the inspection period, a formal program had not l been implemented to address GL 89-13, items 1 or 3 recommended actions. In addition, the licensee had not implemented testing necessary to address GL 89-13, item 2. Further, actions associated with item 5 were incomplete, in that, reviews performed were not appropriately documented neither initially nor after a licensee internal audit identified documentation discrepancies. This is an apparent violation (eel 50-245/96-09-08) of 10-

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CFR 50.9(a), which requires information provided to the NRC by a licensee to be complete and accurate in all material respect Report Details Summarv of Unit 2 Status Unit 2 entered the inspection period with the plant in cold shutdown. On December 18, 1996, the unit entered Mode 6 (refueling) to support a planned core off-load that is needed to support a safety injection valve repair. The unit was initially shut down on February 20, 1996, to address containment sump screen concerns and has remained shut down to

address an NRC Dernand for information [10 CFR 50.54(f)] letter requiring an assertion by l the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Report.

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j U2.1 Operations U201 Conduct of Operations

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01.1 General Comments (71707) i j Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing ;

} plant operations to ensure that licensee's controls were effective in achieving continued .

l safe operation of the facility. The inspectors observed that proper control room staffing !

l was maintained, access to the control room was properly controlled, and operator behavior l was commensurate with the plant configuration and plant activities in progress. In general, l the conduct of operations was professional and safety-conscious. Section U1.06.2 l discusses a site-wide issue involving the failure to update technical specifications to reflect organizational changes. Other specific events and noteworthy observations are detailed in the sections below.

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O 1.2 Adverse Condition Reoort Backfoo Scope

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The NRC evaluated the timeliness in which the licensee completed corrective actions associated with Unit 2 adverse condition reports (ACRs).

l Observations and Findinos

! Timeliness for completion of corrective actions has been a longstanding concern at ,

Millstone. Several months ago, the NRC raised a concern that the licensee's ACR database did not allow them to determine the number of ACRs having outstanding corrective'

l actions.' Since that time, the licensee has corrected ACRs data entries to be able to l l provide reliable ACR backlog number l Having an ACR backlog in itself is not a reflection of poor performance because as the l threshold for writing ACRs decreases, the ACR backlog willincrease accordingly. The I concern is the number of ACRs 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 ACRs having outstanding corrective actions i that are greater than 120 days old. Although the NRC does not consider 120 days a level

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of excellence nor is it acceptable when addressing immediate safety concerns, it does l provide the some undsrstanding of licensee management effectiveness in addressing the i corrective action timeliness issue.

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At the ended of the inspection period, there were 732 ACRs greater than 120 days old that have not been closed. The following table provides the number ACRs by department in which they have an open assignment (i.e., if one ACR has open assignments in several departments, the ACR is counted for each applicable department.)

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l l Maintenance and Work 90 l Planning

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Other 78 TOTAL 940-i l Conclusion

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The above ACR backlog numbers indicate that timeliness for completing corrective actions, particularly in the design engineering department, is a concern. As discussed in inspection Report 50-336/96-04, timeliness and effectiveness of corrective actions is an area in j which the licensee must demonstrate sustained improved performance before the NRC will i allow the unit to restar .3 Reportability Evaluation Form Backloa Scope The inspector reviewed the backlog of approximately 90 reportability evaluation forms (REFs) that had not been dispositioned by the license Observations and Findinas The Shift Manager makes the initial datermination of reportability when an adverse condition report (ACR)is generated based on his best judgment given the limited amount of information that is available at that time. However, in many instances, further review is~

necessary, such as historical reviews or engineering evaluations, to confirm that the initial reportability determination was correct. The REF is the licensee's mechanism for tracking this follow-up review. However, a backlog of approximately.90 REFs had accumulated, ,

with most of them greater than 30 days old.10 CFR 50.73 requires that licensee event I reports be submitted to the NRC within 30 days. The NRC position regarding timeliness of l reporting is that the 30-day clock starts at the discovery date, which is normally the ACR  !

initiation date. Therefore, the REF backlog greater than 30 days old is a concern because-if, through further review, the issue was found to be reportable, the licensee could not satisfy the 30-day requirement of 10 CFR 50.73. Following discussions with the .;

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inspector, the licensee expedited their review of the 90 outstanding REFs and determined that none were reportabl As corrective actions, the licensee is in the process of preparing guidance for reportability determinations that defines how long they have to confirm the initial reportability 1 determination while allowing sufficient time to prepare an LER if necessar ' Conclusion Given the fact that reportability timeliness has been a longstanding issue at Millstone, licenseo performance was weak in allowing a backlog of 90 reportability evaluations to develop. As a corrective action, the licensee is developing guidance for dispositioning reportability evaluations such that the 30-day reporting requirement of 10 CFR 50.73 is satisfied. The NRC will continue to monitor licensee performance in this area when reviewing licensee event report .4 Inadvertent Reduction in Soent Fuel Pool Level Scope The inspector reviewed an event involving the inadvertent reduction in SFP leve Observations and Findinas On November 8,1996, a plant equipment operator (PEO) noted that the spent fuel pool level had decreased by 1 % inches (approximately 1000 gallons) during the shift and that there was a corresponding level increase in the aerated waste drain tank. Shift personnel checked the position of valves that could provide this drain path. The Shift Manager noted .

that some " slack" was present in valve 2-RW-148B, the "B" SFP Purification Pump Casing !

Drain, but the valve was not sufficiently open to make it obvious that this was the drain I path and therefore, they were uncertain they had stopped the drainin The licensee established an ERT to determine the cause of the draining. The ERT found j that the draining began when a push cart struck the handwheel of valve 2-RW-148B. The i

. valve handwheel had a mark of blue paint, which was the color of the cart and personnel working in the area confirmed that they may have hit the valve with the cart. Testing by the ERT found that the valve need only be opened one-tenth of one turn to pass the 2 to 3 gallons per minute flow rate that was experienced during this even As an immediate corrective action, the handwheel from valve 2-RW-148B was remove The safety significance of this event is minimal because the SFP is designed to prevent a significant amount of draining by placing the purification suction line high in the SF Conclusion Overall licensee performance regarding the SFP draining event was good in that: (1) the PEO noted the small reduction in SFP level which prompted the valve position checks that stopped the draining; (2) management established an ERT to determine the root cause of

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! to identify the root cause which was not readily apparen I

U2 O2 Operational Status of Facilities and Equipment O 2.1 Final Safety Analvsis Reoort Verification A recent discovery of a licensee operating their facility in a manner contrary to the final safety analysis report (FSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the FSAR descriptions.

l While performing the activities discussed in this report, applicable portions of the FSAR ( were reviewed related to the examination topic associated with control element assemblies

! (CEAs). The inspectors reviewed surveillance procedure SP 21010 "CEA Drop Times,"

that was performed on July 8,1995, and concluded that the recorded drop times were within the 2.75 seconds assumed in the accident analysi U2 03 Operations Procedures and Documentation

03.1 Svoassino Automatic Actuation of Plant Protective Features Scope Due to concerns raised while observing the annual emergency preparedness (EP) exercise on November 21,1996, the inspector evaluated procedures and operator training associated with bypassing the automatic actuation of the safety injection actuation system (SlAS). Observations and Findinos The scenario for the annual EP exercise involved a 45 gpm tube leak in the No.1 steam generator. Over a period of approximately one-half hour, several prolonged discussions

! occurred among alllicensed operators regarding whether they should block the automatic l SIAS that occurs when reactor coolant system (RCS) pressure reaches 1600 psi. The

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question was initially raised because charging pump flow was sufficient to maintain pressurizer level. In addition, Emergency Operating Procedure (EOP) 2534, " Steam Generator Tube Rupture," Step 2.14.f, refers to Operating Procedure 2207, " Plant Cooldown," for additional actions during cooldown. Operating Procedure 2207, Step 4.6, states that when the pressurizer pressure SIAS manual-block-permitted annunciator is lit at approximately 1750 psi, manually block SIAS actuation. Operating Procedure 2207 was

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written for a normal plant cooldown in which manually blocking SIAS actuation is an i appropriate action. The operators consulted with the Technical Support Center who advised them that automatic actuation of SIAS should not be blocked.

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NRC Information Notice (IN) 92-47, " Intentional Bypassing of Automatic Actuation of Plant Protective Features," which discusses that following the Three Mile Island accident, the NRC issued a series of Bulletins requesting licensees to review operating procedures and training to ensure that operators do not override an automatic engineered safety features actuations without carefully reviewing plant conditions. In the licensee's internal response l

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to the information notice, the only discussion of EOPs was that Unit 2 EOPs contain )

specific guidance for operation of safety related equipment (throttling, stopping and

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restarting) based on identifiable plant conditions. Operator training associated with the ,

information notice focused on events involving stuck open spray valves rather than j defining when engineered safety feature actuation may be bypasse ' Conclusion  ;

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i Although the licensee was made aware of the concern in NRC Information Notice 92-47,  !

during the annual EP exercise, the operating procedures and management expectations l were not clear regarding when operators may override an automatic SlAS actuation. ' This I issue is considered unresolved to allow the licensee to review the procedures and training l to address this concern. (URI 50-336/96-09-09)

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U2 05 Operator Training and Qualification j 05.1 General Scope (71001) i An announced inspection of the Millstone Unit 2 licensed operator requalification program e was conducted from November 18 to November 22,1996, using NRC Inspection .

< Procedure 71001. The scope of the inspection included observation of annual operating examinations for one crew of licensed operators and review of written examinations j administered during this and the prior requalification year. The inspection objectives; 4 l included verification that the requalification program effectively evaluates how well crews and individual operators have mastered training and performance objectives related to plant q safety.

05.2 Examination Material l

l Insoection Scoce

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! The inspectors reviewed annual written examinations for this year and the prior year and q weekly progress review quizzes for this year. Operating examination material was .1 reviewed for the examination being administered during the inspection, and the

! examination scenario bank for this year and the prior year was sample Observations and Findinas The inspectors reviewed written examinations administered during the current requalification segment and two written examinations from the previous year. The questions.were found to be of good quality, with an appropriate mix of high and low cognitive level questions. The distribution of questions was based on training time expended. The individual questions and the sample plan were linked to lesson objectives

! and important job task analysis (JTA) items. Overlap from week to week was limited to 8

of 40 questions. The facility has ceased the use of confidence weighted testing, and had i modified questions for these examinations to the more common four-selection, multiple-choice style.

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l 26 The inspectors observed twelve different Job Performance Measures (JPMs) sets. The sets were of good quality and individual tasks all required significant operational activity by the examinee Simulator Scenarios The inspectors reviewed 15 scenarios from the 1996 examination bank and 12 scenarios frnm the 1995 examination bank. The inspectors noted a lack of diversity in these scenarios in that a limited selection of failures was used, and major transients always used the same event development. For example, a LOCA scenario would always start as a 60 gpm leak then increase to 3000 gpm. In addition, a decline in diversity was noted from the 1995 bank, which in turn was less diverse than prior years. The licensee attributed this decline to personnel turnover, the use of a contractor to develop scenarios, and an attempt to increase the level of detail in scenario writeups. The licensee stated they were aware of the problem and were intending to return to an earlier method of scenario i

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development using a listing of failures to mix and match with the major transient Although the bank lacked diversity, the scenario sets run met the criteria of the examiner standard Conclusiong The licensee did a vesy good job in developing the written examination, which was much improved from the prior inspection. They also did a good job in preparing the job performance measures. One program weakness was that the simulator examination scenario bank lacked diversity, covering a limited set of failere j 05.3 Trainina Content Insoection Scooe The inspectors reviewed lesson plans and feedback mechanisms to verify that plant and industry events, modifications, and personnel feedback were incorporated into trainin Observations and Findinas The inspectors reviewsd the facility process for incorporating plant and industry events into training. This was primarily the responsibility of the operations department, which has an individual assigned to revit.w such events and prepare training. He is allocated a block of time in each requalification week for this purpose. Additional training needs were also identified by operations management and communicated to training by meeting or memorandum. Examples of training based on event review or operations request included:

(a) Tabletop scenarios for evaluation of CEA technical specifications; (b) Electrical print *

l reading; (c) Operability considerations with loss of a power source; and (d) Heatup and l cooldown operations.

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Other feedback comes from evaluation of examination results, student feedback forms, and individual crew mentors. Trainee interviews indicated that these mechanisms have been effective in modifying training, with the mentors being particularly effectiv Conclusions The facility has effective mechanisms for modifying training in response to plant and industry events and other identified need .4 Examination Administration and Evaluation Insoection Scoce The inspectors observed one crew perform two simulator scenarios and observed the individuals in this crew perform sets of 5 JPMs. The inspectors also observed facility evaluation of crew and individual performanc !

i Observations and Findinos The crew and allindividuals passed their written and operating examinations. Two individuals failed one JPM eac Overall crew and individual performance in the simulator was good, and the crew worked together to perform all critical tasks successfully. Some weak command and control was observed in both scenarius in incomplete and unclear orders concerning emergency boration, boration while moving rods, and specifying control bands. In one scenario, deficiencies were noted in communications outside the control room due to an excessive 3 delay in event classification and in notifying site personnel of a steam generator tube leak l with a steam lea i Facility evaluation of crew performance was thorough and detailed, and identified numerous instances where performance could be improved in effectiveness of communications, command end control, and self-verification practice Although facility evaluation pwctices in the JPMs were generally acceptable, two instances ,

were observed where the evaluator provided too much guidance while role playing as the '

shift supervisor. In one instance, the candidate was told to "look at the valves" in a JPM where the task involved diagnosing a valve failure to position, and in an instrument failure JPM the candidate was directed to evaluate the validity of instrument indications. These instances did not appear to be deliberate prompting, but indicated a need for further guidance to the evaluator on appropriate means of simulating the supervisor. Facility management observed these instances and counseled the evaluator, resulting in improved evaluator performance in subsequent JPM Conclusions

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Crew performance was good. Performance deficiencies which existed were appropriately evaluated by the facility, j l

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05.5 Remedial Trainina Scope -

The inspectors assessed the adequacy and effectiveness of remedial training conducted i during the examination cycle, including training provided to operators to correct ,

deficiencies which prevented them from successfully passing examinations as well as '

training provided to correct generic weaknesses which had been observed during *

requalification training and plant operations. The inspectors performed the assessment through the review of training and examination records, interviews with operators and l

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instructors, and the observation of remedial training administered during the week the inspectors were on sit Observations and F;ndinos The inspectors reviewed the written quiz and examination scores of alllicensed operators '

for the two-year requalification training cycle and verified that any operator who had failed I a test had subsequently passed a retake examination. The inspectors determined that all l chronically weak performers had previously been identified by the training staff, and those

- operators had either been removed from licensed duties or had been placed in special  !

, remedial programs. Each Millstone Unit 2 operating crew has been assigned a specific j training staff instructor as a mentor who provides a direct interface between the training department and the crew and who works with the crew to identify and address any

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individual or crew-wide deficiencies. The inspectors did not identify any cases where the need for remediation was indicated and had not been provide During the week the inspectors were on site, they observed portions of the remedial

. training being provided to an operating crew which had failed their annual operating test; a the previous waek. The inspectors reviewed the grading forms from the failed operating ; '

test and the remediation plan developed by the crew's mentor. Through this document review and the observation of simulator training provided to the crew, the inspectors determined that the training staff had properly identified the operators' weaknesses and had developed and administered effective remedial trainin By reviewing training records, observing operator simulator training and testing, and observing instructor crew critiques, the inspectors determined the Millstone IJnit 2 training staff identified and responded to areas of generic operator weakness. During the previous requalification cycle the training staff had identified the areas of instrument:: vion knowledge and crew communications as generic areas for crew performance improvement. The inspectors determined that simulator scenario events and instructor grading of those events had supplied effective generic remedial training in those area Conclusions The inspectors concluded that the Millstone Unit 2 remedial training program was being effectively implemented. The unit's training staff had properly identified and responded to both individual operator and generic weaknesses over the past requalification cycle. The

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inspectors noted the use of the mentor prograrr te os especially effective in identifying operator deficiencies and developing remedial training to correct them.

U2.11 Maintenance

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U2 M1 Conduct of Maintenance

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M 1.1 Verbatim Comoliance with Technical Soecification Surveillance Reauirements Scooe

! The inspector reviewed selected items in surveillance procedure SP 2614A, " Periodic 1 Checks in Mode 5 and 6 or When Defueled," and evaluated whether this procedure satisfied the associated surveillance requirement specified in technical specifications (TSs).

Observations and Findinas .1 i l

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TS 4.1.2.3.3 states that all high pressure safety injection (HPSI) pumps not intended to be

capable of injecting, shall be demonstrated inoperable at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by either

(a) verifying that the motor circuit breakers have been disconnected from their power -

' supply circuits, or (b) shutting and tagging the discharge valve with the key lock on the control panel. The inspector found that rather having a direct visual verification that the l motor circuit breakers have been racked out, which could be accomplished during plant equipment operator rounds, the licensee satisfies this TS by performing shiftly control room j

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logs per procedure SP 2614A. The licensee stated that the method control room operators i used to verify motor circuit breakers have been disconnected was to verify that the tag i

was hanging on the HPSI pump control switch and that the control switch lights were

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deenergized. 'Since the control switch lights could be deenergized for various reasons-

other than the breaker being racked out, the licensee stated that the tag was the primary i metho The NRC determined that although verifying the HPSI pump control switch is tagged provides a high degree of confidence that the breaker is racked out, this does not satisfy the literal words of TS 4.1.2.3.3. This position is supported by the fact that as opposed to option (a), option (b) of TS 4.1.2.3.3 specifically delineates when tagging provides an acceptable means of satisfying the surveillance requiremen The inspector discussed the concern with the Operations Director, who agreed with the .

NRC position. As a corrective action, surveillance procedures were changed that day to have the plant equipment operator perform the visual verification that the breaker is racked out. In addition, the licensee performed reviews to identify other TS literal compliance issues, regardless of whether the surveillance satisfied the intent of the TS or whether the discrepancy was safety significant. This review revealed a number of other TS noncompliances which, in addition to the TS 4.1.2.3.3 concern, the licensee plans to report in accordance with 10 CFR 50.7 O 30 Conclusion The failure of the licensee to adequately verify that the HPSI pump motor circuit breakers have been disconnected from their power supply circuits is a violation of TS 4.1.2. This failure constitutes a vio!ation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy. Other TS literal compliance issues discovered by the licensee will be inspected as part of the NRC review of the associated licensee event report U2 M8 Miscellaneous Maintenance issues M 8.1 (Closed) Unresolved item 50-336/96-05-08: Procedure Comoliance Durina Emeroency Diesel Generator Reoairs Insoection Scongt

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. An NRC inspector noted that the licensee event review team investigating the cause of the

"B" EDG failure had documented two potential procedure non-compliances in their  ;

preliminary report. This issue was unresolved pending licensee issuance of the final event review team report and NRC revie l

. Observations and Findinas The potential procedure non-compliances involved questions regarding the need to clean the crankshaft during the March 1996 bearing replacement and regarding the need to remove the upper crankshaft to perform inspections and repairs following a bearing failure.

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.The ERT reviewed the question regarding the need to clean the crankshaft anc during interviews with the maintenance personnel found that there had not been aluminum *

transfer to the crankshaft but only dark discolorations which are normal. The ERT concluded that a procedure non-compliance did not occu The issue regarding the need to remove the upper crankshaft was reviewed and the ERT found that this step is only necessary when the failure involves a thrust bearing. Since the failed bearing was not a thrust bearing, the maintenance supervisor concluded that the step could be omitted. The ERT recommended that the maintenance procedure be revised to clarify the step and the administrative procedures be changed to provide more detail as to what changes f all under the authority of the first line supervisor. The current controls permit the supervisor to delete entire steps that are not applicable to the job being performe The ERT also concluded that these issues did not have any impact on the repairs being performed and did not contribute to the subsequent engine bearing failure s i

31 Conclusion The inspector reviewed ERT members and reviewed the ERT report and associated ACRs that documented the issues. The inspector concluded that the ERT had appropriately evaluated and dispositioned the procedural issues. This item is close U2.lli Enaineerina U2 E1 Conduct of Engineering E Preoarations for Entrv Into Mode 6 - Refuelino Insoectinn Scooe (37551)

As discussed in NRC inspection Report 50-336/96-08, the NRC had concerns regarding the licensee's intent to enter Mode 6 and perform a core offload using systems which, although operable, had known discrepancies that were contrary to the current operating license. Although no violations of NRC requirements were identified, this was considered to be a significant weakness in light of recent attention given to compliance with the

, current design and licensing basis. As a result of this concern, the licensee first focused on systems necessary for entry into Mode 6. This inspection evaluated whether the licensee adequately dispositioned known licensing and design basis discrepancies associated with entry into Mode Observations and Findinos The licensee developed a written plan for evaluating and dispositioning known design discrepancies on safety-related systems that are necessary to support Mode 6 and corey offload. Discrepancies would be dispositioned by either correcting the plant to reflect the design or licensing basis or by changing the design or licensing basis using the 10 CFR 50.59 evaluation process to reflect the plant. The review process is being performed in two phases with the first phase focusing on the transition to Mode 6 including reactor vessel head removal and flood up of the refueling cavity. The second phase of the review includes those systems needed to support fuel movemen The results of the initial phase review were documented in a report dated November 15, 1996, and were approved by the Plant Operations Review Committee on November 18,,

1996. The report documents the deficiencies that were identified, the 10 CFR 50.59 evaluations that were performed, the FSAR change requests (FSARCR) that were generated and a list of open items that were recommended for closure prior to entering Mode For those systems that were not part of the Mode 6 review, the licensee still screened the known deficiencies for their effect on Mode 6 operations and dispositioned the deficiencies as necessary. The licensee plans to complete a full discovery on those systems at a later time. The inspectors reviewed a sample of several hundred known deficiencies for those systems that were not part of the licensee's Mode 6 review to determine if any of the

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deficiencies that were screened out should have been dispositioned prior to Mode 6. The inspector did not find any instance where a deficiency was inappropriately screened ou For those systems included in the Mode 6 review, the inspectors verified that discrepancies that had not been dispositioned were included in the Mode 6 restraint schedul The 50.59 evaluations that were performed were found to be of high quality and review of ;

the evaluations by the Plant Operations Review Committee was thoroug ! Conclusions The licensee's process for dispositioning known design and licensing basis discrepancies that could adversely affect Mode 6 operations was effective and no concerns were identifie I U2 E2 Engineering Support of Facilities and Equipment E "B" Emeraencv Diesel Generator Failure l l Insoection Scone (37551)

The inspectors reviewed the licensee's investigation of the failure of the "B" emergency-diesel generator (EDG) that occurred on April 17,1996. The engine experienced severe damage to the upper crankshaft main and connecting rod bearings during surveillance testing. The inspector's review primarily focused on the licensee's root cause investigation and the corrective actions to prevent recurrenc l Observations and Findanas l

Following the EDG failure, the licensee formed an event review team (ERT) to perform a- I root cause analysis and recommend corrective actions. The current "B" EDG engine has )

been in service since 1977 following the failure of the original EDG. During the initial site !

acceptance testing of the new dieselin 1977, the lube oil pressure was approximately 1 26.5 psig which was marginally above the minimum value of 26 psig specified in the .

vendor technical manual for the diesel. During the first several years of operation, the EDG experienced a large number of engine starts that included more than twenty " emergency" l starts (i.e., no pre-lubrication) per year in 1977 and 1978. The licensee subsequently modified the starting logic so that the EDG would only emergency start on a loss of normal power or a safety injection initiations signal. While the number of emergency starts was i reduced, the licensee continued to perform monthly pre-lubricated (prelube) fast starts to fulfill technical specification (TS) surveillance requirements. Also, based on a vendor recommendation that the EDG bearings be lubricated every few weeks, the licensee chose to start the engines and operate them unloaded for two to three minutes once per mont i For a period of time, the licensee was starting the EDGs once per week due to other i reliability concern Between 1978 and the time of the engine failure, there were nine occurrences where the licensee identified and replaced one or more degraded bearings on the upper cranklin !

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33 These conditions were discovered when the engine was disassembled for periodic maintenance or repairs and did not result in operational failures of the diesel.

, in March 1996, approximately one month prior to the diesel failure, significant degradation of number 9 upper main bearing had been identified during the performance of the 18-month engine inspection. The removal of this bearing was prompted as a result of the parting line check not meeting the acceptance criteria. [A parting line check involves using a feeler gage to check the clearances at the area that the two halves of the bearing inserts contact each other, as well as the clearances between the outside of the bearing inserts and the engine saddle or bearing cap. Ideally, there should be no clearance. The bearing fails the parting line check if a gap develops that allows insertion of a 0.002 inch ,

feeler gage. The parting line check of the number nine upper main bearing found a 0.004 i inch clearance. A failed parting line check is an indication that significant bearing heating has occurred resulting in permanent distortion of the bearing insert.] A visual inspection following the bearing removal indicated that the bearing had experienced significant flashing, which occurs when there is no lube oil film on the bearing surface resulting in metal-to-metal contact between the bearing and crankshaft resulting in pickup and smearing of the bearing material. A srnall amount of flashing occurs during engine starts until a lube oil film develops and the amount of flashing is minimized by pre-lubricatio Although this minor flashing is accumulative, the bearing tends to " heal" itself if operated for a period of time, thereby making the short diesel runs (such as the monthly 2-3 minute i run) undesirable. Insufficient lube oil worsens the extent of flashing which can cause the I bearing to overheat. Depending on the magnitude and duration, overheating a bearing can warp the bearing insert, which was observed in March 1996, or it can overheat to the point where the bearing material actually melts, which occurred in April 1996, resulting in i significant engine damag ]

l Following the March 1996 parting line check failure, the licensee did not perform a root-cause analysis of the failure and was therefore _a missed opportunity to correct the l insufficient lubrication problem that caused the overheating. Rather, the licansee's l corrective actions simply involved replacing the bearin l Although the March 1996 inspection was the first time a main bearing had failed its parting i line check, in 1983, the upper number 13 thrust bearing failed its parting line check and I was found to be badly flashe '

The ERT concluded that the cause of the engine failure was inadequate lubrication of the upper crankshaft bearings. The ERT identified the following five failure mechanisms that contributed to the inadequate lubrication:

e inadequate oil pressure to the upper bearings resulting in marginal lubrication when l the engine is started, i l

l e Inadequate oil pressure combined with a transient of entrained air in the tube oil l during engine starts; e Inadequate prelube resulting in a period of unlubricated operation after the engine was f ast started; i

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• Cumulative bearing damage during fast starting that did not " heal" during short l unloaded runs, and; l

• Clearances in the number 8 and 9 upper bearings that were replaced in March 1996 '

were probably tighter than the other bearing Based on the identification of the above failure mechanisms the ERT identified six root l causes that enabled the failure mechanisms to be present: l

• Technical information provided by the EDG vendor was less than adequate for I reliable operation

• The investigation of the March 1996 failure was inadequate; l

• Use of industry and vendor information and analysis of operating data was not adequate;

• The lube oil system design is marginal to support frequent f ast starts;

• Information was not shared between Unit 1 and 2; and l

• Decisions about EDG operation focused primarily on operability rather than reliability issue The corrective octions that have already been implemented to prevent recurrence include j the following: l

• The number of fast starts has been reduced by replacing the 2-3 minute unloaded ;

run with a prelube followed by an air roll of the engine; I

• The prelube time prior to engine starts has been increased based on engine specific prelube testing. Also, during starts the prelube is maintained during the start until oil pressure is 5 to 10 psig; I

• The engine oil pressure following the repairs has been increased to approximately 37 psig; and

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• A vent line from the lube oil cooler to the crankcase was installed to enable the l

removal of air from the syste A s,ignificant number of additional actions are planned or are under evaluation and include:

l * Revising the technical specifications to further minimize the number of fast starts i during surveillance testing;

• Improvements to the emergency diesel generator performance monitoring program; I and s l

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e Revision of procedures to increase run-in time following bearing replacement _ Conclusions The inspectors concluded that the ERT performed a thorough evaluation of the causes of the EDG failure and provided a comprehensive list of corrective actions. The immediate corrective actions appear to be appropriate to prevent a recurrence of the failure and the additional actions that are planned should further reduce the potential for a repeat failur The inspectors also concluded that the licensee's actions in response to industry operating experience associated with similar engines were inadequate and generally used for a basis to support the fact that engine failures had not been experienced at Millstone 2. In particular, all engine starts were fast starts, and the frequency with which engine fast starts were performed was excessive when compared to general industry practice. Als],

the licensee failed to identify the root cause of and take corrective action for the #9 main bearing failure that was discovered in March 1996. The failure to take corrective action for that f ailure constitutes an apparent violation of 10 CFR 50 Appendix B, Criteria XVI. (eel 50-336/96-09-10)

Report Details l

Summarv of Unit 3 Status Unit 3 remained in cold shutdown (mode 5) status throughout the inspection period. The licensee continues to implement configuration management program activities, engineering 1 reviews, and docketed correspondence assessments to verify compliance with the i established design and licensing basis of the unit. The successful completion of such !

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i activities is required by the NRC* prior to restart of the plant. Additionally, in a letter to the )

i NRC dated December 27,1996, the licensee provided a description of the process  !

intended to assemble corrective action completion packages for NRC inspection items, !

restart issues, and reportable events. The development of such a process by the licensee establishes licensee criteria for corrective action documentation and details a standard way of providing objective evidence of corrective action completion. As the licensee i

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configuration management program and corrective action completion activities progress, NRC evaluation of corrective action effectiveness and open technical issues will also continue, in the future to be f acilitated by the corrective action completion package I reviews.

l U3.1 Operations

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l l U3 01 Conduct of Operations

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01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations, particularly with respect to plant shutdown risk management controls. In addition to plant inspection-tours and control room observations, the inspectors attended plant operations review committee (PORC) meetings, reviewed operability determinations

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(ODs), and witnessed the conduct of management review team (MRT) discussions regarding the disposition and closure of adverse condition reports (ACRs). Where appropriate to the resolution of specific adverse conditions (e.g., ACR 11322), licensee reportability determinations were also reviewed and the documented information was checked for consistency with the Unit 3 final safety analysis report (FSAR) and the applicable operating procedures. The inspectors conducted control panel and field -

equipment inspections, as necessary to verify licensing basis commitments, general design criteria compliance, and hardware configuration details in line with piping and instrumentation diagram ano isometric drawing requirement In the specific case of ACR 11322 followup, the licensee evaluation and corrective action efforts were determined to be adequate for closure of the identified containmert isolation concern. The inspector noted a difference between the actual plant configuration for the electrical power supply to four containment isolation valves and the power sources listed in FSAR Table 6.2-65; however, this discrepancy had already been identified by tha licensee using project instruction (PI) 19 for FSAR verification in the implementation of its configuration management plan. The licensee indicated to the inspector that this issue has already been scheduled for resolution as part of the licensee's ongoing FSAR upgrade projec Overall, the conduct of operations during this inspection period was found to be daliberate and professional, with the licensed operators and operations supervisory personnel demonstrating an appropriate respect for shutdown risk criteria in operational evolt tions and scheduled equipment outages. Additionally, during daily plant status meetings, as well as in the conduct of PORC and MRT meetings, licensee management continues to demonstrate a good questioning attitude and sound approach to the evaluation and resolution of the concerns being identified in ACRs and also in conjunction with the configuration management program. While the implementation of effectiva corrective-actions remains as a management objective not yet fully realized, certain operational v program controls (e.g., the processing of ODs, the handling of bypass-jumpers) have been found to be effectively managed during this inspection perio U3O2 Operational Status of Facilities and Equipment O2.1 Batterv Confinuration and Modification Controls (71707, 92901) Insoection Scooe The inspector e>iamined the material condition, configuration status, and operability of all four,125 Vdc safety-related station batteries. Operational control of a bypass-jumper installed on one battery was reviewed, as was the technical evaluation and applicable OD supporting continued operability of the battery with the temporary modification in plac The inspector checked system operating and preventive maintenance procedures for the 125 Vdc batteries to confirm consistent criteria for the battery charging, float voltage, end cell jumpering, and examined the field conditions for verification that the applicable criteria had been met.

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37 Observations and Findinos t3atteries 1 and 2 are similar 125 Vdc batteries (Gould NCX-1650 ampere hours) with the design capability to power the "A" and "B" train de bus loads in addition to the uninterruptible power supply to safety-related instrument channels "A" and "B" respectively. Batteries 3 and 4 are similar, but smaller 125 Vdc batteries (Gould NCX-750 ampere hours), associated with train "A" and "B" distribution systems and designed to supply safety-related instrument channels "C" and "D" respectively. On Battery 2, cell 44 was jumpered out in accordance with bypass-jumper 3-96-077 because of low individual cell voltage. In support of the technical evaluation for this bypass-jumper installation, a battery sizing and charging calculation was marked up to document the effect of removal of one cell from the 60-cell series connection comprising battery The inspector reviewed bypass-jumper 3-96-077, the associated technical evaluation and I the supporting calculations, i.e., revised Calculation 188E. The inspector checked the ,

temperature correction factor, the design margin, and the aging factor used in the calculations for consistency with the guidance provided in IEEE standards 450 and 48 The inspector also confirmed that the battery charger loading calculations had appropriately taken into account the steady-state loads discussed in FSAR section 8.3.2.1.2.1, as recommanr'ad in USNRC Regulatory Guide 1.32, Revision 2. As noted in an assumption I for the revised calculations that battery 2 would be replaced prior to operation below 85% l of rated capacity, the license has scheduled the replacement of battery 2 in a late January l or early February,1997 time fram During field inspections of all four batteries, the inspector noted different inter-rack and input / output terminal connections for the different batteries. These configuration !

differences were discussed with the licensee, who received documented correspondence l from the battery vendor that the1various methods for terminating cables and jumpering across racks were acceptable options and consistent with the battery qualification record ]

The inspector also evaluated the identified conditions with regard to system operating l procedure OP 3345 (revision 14), maintenance procedure MP3780AA (revision 5), and I common maintenance procedure (CMP) 755D (revision 0). In accordance with MP 3780AA, the float voltage for battery 2 had been reduced based upon the removal of cell 44. An index card, dated August 17,1996 (i.e., the date of approval of bypass-jumper 3-96 077) had been affixed to battery charger 301B-1 to note the expected reduction in float I voltage. While this information was technically correct, the inspector noted that the Unit Director removed this index card during a plant walkdown, because it constituted an unauthorized operator aid. Subsequent discussion between the inspector and the Unit Director confirmed licensee management's intentions to upgrade all plant material conditions, including usage of operator aids, to the standards consistent with approved procedural control c Conclusions The inspection of Unit 3 station batteries 1 through 4 identified some configuration differences, but no adverse conditions that would raise concerns regarding the operability or qualification of these safety-related batteries. An evaluation of the controls and supporting documentation for the installation of an electrical jumper to bypass a deficient . . . . _ . . _ _

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cell on battery 2 revealed an adequate basis, compliance with regulatory commitments and l standards, and technical calculations to support the temporary modification. The inspector i identified no unresolved safety concerns as a result of the 125 Vdc battery inspection U3 08 Miscellaneous Operations lasues (92700)

08.1 (Closed) LER 50-423/96-04:

The turbine driven auxiliary feedwater isolation valves were shut in violation of technical .)

specification (TS) 3.7.1.2 on several occasions when reactor power was below ten l I

percent. The licensee had erroncously used a TS surveillance requirement to take )

exception to a TS limiting condition of operation. This issue was discussed in NRC  !

Inspection Report 423/96-201, and constituted an apparent violation of TS and 10 CFR l 50.59. This LER is close i l

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U3.Il Maintenance >

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U3 M1 Conduct of Maintenance M1.1 General Comments Insoection Scooe (62707/61726) ,

l The inspector observed / reviewed all or portions of the following maintenance and l surveillance activities:

l e M 3-96-14831, Remove / repair charging header loop drain valve 3CHS*V830 e M 3-96-17736, Modify service water strainer element '

• M3-96-17740, Modify service water strainer element

• SP 3604A.3, " Charging Pump "C" Operational Readiness Test"

• SP 3604C.1, " Borated Water Source and flow Path Availability Verification" e SP 3604C.2, " Monthly Borated Water Flow Path Verification"

• SP 3712NA, " Battery Surveillance Testing" - quarterly test Observations and Findinos The inspector found the work performed under these activities to be professional and thorough. All activities observed were performed with the work package or surveillance procedure present and in use. Pre-job briefings were conducted pr:or to the performance of each surveillance observed. Review of the surveillance procedures revealed that the

requirements of the applicable Technical Specification (TS) were appropriately incorporated into the implementing procedure. However, procedure SP 3712NA incorrectly listed the  !

l acceptance criteria for battery specific gravity as greater than or equal to 1.205, whereas TS specifies greater than 1.205. The licensee was informed of this discrepancy. An adverse condition report was written to document this conditio ! in addition, see the specific discussions of maintenance / surveillance activities observed i under M1.2 and M1.3, belo l

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l 39 l M1.2 Work Activity Stand-Down Insoection Scooe (62707)

A stand-down from all work activities was held on December 10,1996, to allow management to convey their standards and expectations to the craft (including contract employees). The inspector attended the maintenance department stand-down meetings to I monitor what expectations were being conveyed by management and to determine tha I craft participation and reception of the materia ;

1 Observations and Findinas l

The work stand-down lasted approximately two hours. The expectation was that all Unit 3 l employees would attend one of their department meetings. The maintenance departrnent I was broken down into five groups with each maintenance supervisor briefing their I department staff. Contractors were present at the group meetings as well as a representative from the quality assurance organization. The quality assurance department l representative attended one of the five maintenance group discussiens to determine if all l departments were clearly conveying management standards and expectations. Also, the l maintenance manager attended part of each group meeting to monitor the exchange of i information and to answer any specific questions from the craf A briefing sheet was provided by the recovery manager for use by each supervisor to !

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discuss plant material condition, control room notification, work practices, procedure l compliance, and technical specification compliance. The inspector noted that there was active discussion between the craft and the supervisor in each group meeting. Some

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apprehension was expressed by the craft as to whether or not management would supply i the support needed to achieve the desired results. The maintenance manager stressed the '

l point that changes have been made in the upper management of Northeast Utilities in an attempt to improve the performance of the station. Also, the maintenance manager challenged the craft personnel to effect change, not to accept degraded conditions, and ,

not be afraid of any repercussicas for raising concerns. The manager stressed plant I safety, work quality, and senadule as keys to succes !

M1.3 Service Water Strainer Renair

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l Insoection Scone (62707)

l l The inspector reviewed portions of the maintenance activities associated with the repairs i to the service water (SW) pump strainers. Discussions were held with maintenance workers to ensure that personnel were familiar with the temporary repair mocification.

l Observations and Findinas Licensee investigation into the cause of an excessive differential pressure across the "A" reactor plant component cooling water heat exchanger revealed signs of extensive fouling and foreign material. Excessive clearances were measured between the bottom tube sheet and the lower end of the strainer filter elements for the "A" SW pump strainer. Inspection

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of the other three SW pump strainers identified similar concerns. The greatest gap measurement between a strainer tube end and its tube sheet was 0.108 inch, vice the designed value of 0.0625 inch. All four SW pumps were declared inoperable. This condition was properly reported in accordance with 10 CFR 50.72 on October 25,1996, as a condition outside the plant design basi Bypass jumper 3-96-101 was generated to install temporary modified strainer elements in each SW strainer to restore the designed diametral clearances. The modification consisted of weld build-up to the outside diameter of the lower end of the strainer tubes to aid in centering the tube element in the tube sheet. Work orders M3-96-17740 and M3-96-17736 were generated to perform this work. A permanent fix will be implemented prior to the plant entering mode l The inspector reviewed the work packages and verified that the proper procedure for strainer disassembly was referenced, quality control hold points were included to verify the proper dimensions after the weld buildup, and that the maximum strainer dimension -

clearance listed in the package was in accordance with the Final Safety Analysis Report requirements. However, the work order and bypass jumper did not specifically state a maximum tolerance on how far from the bottom of the strainer tube the weld should be applied. The documents indicated that the weld was to be applied at the lower portion of I the tube element. Discussions with the welder revealed that he had been briefed by the l maintenance supervisor of the need that the weld be positioned such that when the tube is installed in the strainer that it fall within the thickness of the tube sheet. Inspection of several strainer tubes by the inspector revealed that the welds were located within one-half 1 inch from the bottom of the tube, and this would result in properly positioning within the strainer tube shee l The inspector also observed the maintenance mechanics during the disassernbly of the "D" l service water strainer. The conduct of the maintenance work was professional and the' I mechanics were familiar with the work procedure. Good procedure adherence was i

demonstrated as evidence by the mechanic stopping the strainer disassembly to question l his supervision regarding whether the planned rigging was a deviation from the method l stated in the work procedure.

M1.4 Cong[gsions on Conduct of Maintenance /Surveillances Activities observed were completed thoroughly, professionally, and in compliance with all stated criteria. With the exception of procedure SP 3712NA, surveillance procedures appropriately incorporated the requirements of the applicable TS. Although the SW strainer work package did not specifically state the exact location of the weld, the work package was adequate to perform the job. Also, during the Unit 3 work stand-down, the inspector observed that the maintenance managers clearly conveyed their standards and expectations, stressed the importance of the maintenance department, and of the need for individuals to accept and effect change to improve the performance of the statio .. . __ - .. -. - - . _ -- - -

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U3 M2 Maintenance and Material Condition of Facilities and Equipment M2.1 (Closed LER 50-423/96-25): Arcor S-30 Pieces Found in the Recirculation Sorav ;

Svstem (RSS) Heat Exchanoer (Ocen URI 50-245/96-09-11 and 50-423/96-QS-11) Insoection Scone (62707)

On July 25,1996, the licensee reported that pieces of Arcor (an epoxy coating applied to j the internal diameter of the service water (SW) system piping to minimize erosion / corrosion) and mussel shells were found in both of the "A" train RSS heat exchangers. The licensee determined that the number and size of this debris could have i prevented the heat exchangers from performing their specified safety function. This issue was reported in accordance with 10 CFR 50.72(b)(2)(i) for a degraded condition identified while shutdown. The inspector reviewed the licensee's corrective action to address this concern, and compared the maintenance procedure to the vendor supplied information for applying Arcor coatin ) Observations and Findinos The licensee found 20 pieces of blue Arcor S-30, the second coat applied to the SW piping, at the temporary inlet screen installed upstream of the "A" train RSS heat exchangers. In addition, 20 to 30 mussel shell fragments were found in each of the heat exchangers. This debris had been swept into the heat exchanger channel head by the SW flow during the engineered safety features / loss of power (ESF/ LOP) test perfonned during the current plant shutdown. Similar flushing of the "B" train SW supply to the RSS heat exchangers during the ESF/ LOP testing resulted in no Arcor pieces or mussel shell fragment The "A" train of the SW system was drained and inspected to determine the location and extent of Arcor delamination. Inspection of the piping revealed that a section of Arcor was missing on the supply piping header spool piece 3SWP-19-4A. The licensee concluded that the size of the delaminated section would account for all the Arcor material collected from the RSS heat exchangers. No other SW piping locations showed signs of delamination: nor were there signs of debris in any other "A" train SW heat exchanger The licensee determined that the Arcor delamination was the result of improper bonding

! between the first and second coatings during application; specifically, due to over curing of the first coating layer prior to the application of the second coat. This was the second occasion at Unit 3 in which the Arcor coating has delaminated. This recent section of piping where the coating was identified as missing was installed in October 1993. The coating was applied in the field, vice in the maintenance shop. The other instance in which the second Arcor coat had delaminated was also field applied. Instances of Arcor

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delamination at Millstone Unit 1 have also been applied in the field. No delamination has

, been recorded at Unit 2.

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1 s l 42 As corrective action, maintenance procedure MP 3710AH, "Arcor Coating," was revised to stress the importance of maintaining satisfactory environmental conditions during coating

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applications, and when the second Arcor coating should be applied. Repairs to the spool piece were made using the revised procedure. As a precautionary measure to prevent Arcor chips from affecting heat exchanger performance, the licensee is considering l installing permanent screens upstream of the RSS heat exchangers. Screens have already j been installed upstream of the emergency diesel generator, reactor plant component l cooling water, and turbine plant component cooling water heat exchangers in 1991 due to concerns with potential mussel shell fouling.

l Arcor coating has been used at Millstone Unit 3 since 1991. It is applied to portions of the l SW piping (copper nickel, monel, and copper nickel clad piping) where degradation has l been observed. The coating has been used predominantly on the SW return piping; i

! however, some areas of supply piping have also been coated. The safety evaluations (SE)

l performed by the licensee to evaluate the use of Arcor determined that the application of ;

L the coating to the SW piping did not constitute an unreviewed safety question. The SE 1 l indicated that the adhesion of the coating had been thoroughly tested at an independent i laboratory, with no loss of adhesion observed. And in the event adhesion is not '

l maintained, the epoxy would chip off and pass through the SW syste i l \

! In the previous coating failure at Unit 3, the Arcor pieces were not large enough to impact l l

any downstream components. However, for this coating failt 3, the pieces were large enough that some became wedged in the tubes and source were large enough to block flow. The licensee stated that although the test flow through the "A" train RSS heat 9 exchangers was adequate, they were unable to conclusively determine that the heat !

exchangers could have met their design heat transfer requirements due to the number and size of debris found in the heat exchangers. A recent delamination of Arcor coating at Unit

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1 also resulted in a piece becoming lodged inside of a heat exchanger tube causing an : .

Erosion induced hole. The licenseo plans to reexamine their safety evaluations for the application of Arcor coating.

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Review of Vendor Information The inspector compared the Unit 3 maintenance procedure MP 3710AH to the vendor manual and noted several discrepancies. These included:

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• The requirement to allow the coating to cure out, if the overcoat window was l exceeded, prior to abrasive blasting to render the undercoat bondable without ,

contaminating it with lodged abrasive particles was not included in the maintenance l procedur e  !

• The maintenance procedure required that the surface temperature of the piping be I verified greater than 5 F above the dew point prior to coating application; whereas the vendor manual recommended that it be maintained once abrasive blasting l l begins and for the duration of the coating operatio * The final cure times were not exactly stated as those in the vendor manua ,

i l in addition, the inspector noted that the Arcor coating was not considered as a quality I l controlled component. These concerns were raised to the licensee. The licensee was

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l already in the process of developing a new Arcor maintenance procedure and had incorporated some of these item The inspector reviewed the original and the new work order that coated spool piece 3SWP-19-4A with Arcor. The cure time listed was in accordance with the maintenance and vendor instruction, in addition, the review of the work orders did not indicate that abrasive blasting due to over curing was necessar Conclusions I The NRC concluded that application of Arcor installed on spool piece 3SWP-19-4A l l

appeared to be applied in accordance with vendor recommendations. The affect of Arcor '

delamination on safety-related components is considered an unresolved items at Units 1 and 3 pending completion of the licensee's safety evaluation review and root cause investigation. (URI 50-245/96-0911 and 423/96-09-11).

U3 M3 Maintenance Procedures and Documentation M 3.1 Aoolication of the Maintenance Rule Procram Scooina Insoection Scooe (62706)

, The inspectors reviewed the Unit 3 scoping process and documentation to determine if the l appropriate structures, systems and components (SSCs) were included within their I maintenance rule program in accordance with 10 CFR 50.65(b). The inspectors used inspection procedure (IP) G2706, " Maintenance Rule;" NUMARC 93-01, " Industry l Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants;" and Regulatory Guide (RG) 1.160, " Monitoring the Effectiveness of Maintenance at Nuclear-Power Plants," as references during the inspection, Observations and Findinas

, NU evaluated 222 SSCs during the initial scoping phase. The facility used the Millstone

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Unit 3 drawing list, nuclear plant reliability data system (NPRDS), probabilistic risk assessment (PRA) system listing, operations department system listing, engineering department system listing, and the Production Maintenance Management System (PMMS),

a computerized data base of all plant systems, to identify the SSCs to be considered for placement under the maintenance tule. Of these,119 SSCs were scoped within the l maintenance rule, and 42 SSCs were identified as high safety significance. Of the 103 l SSCs not scoped in the maintenance rule program as separate SSCs, approximately one

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tenth of the SSCs were included with other SSCs' functions already within the scope of the maintenance rul The scoping process included two phases. The phase one scoping effort was focused at the system level and was a preliminary evaluation of each system against the scoping criteria specified in 10 CFR 50.65. Phase two included analysis and definition of SSC functional significance as they related to the scoping criteri ,

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I The SSCs within the scope of the maintenance rule were listed as an attachment to the l Integrated Maintenance Program Manual, Rev.1, Program Instructions, PI-1.1, Rev.1,  !

l " Scoping Phase 1" and PI-1.2, Rev.1, " Scoping Phase 2." This listing identified the SSCs and their associated maintenance rule function The inspectors reviewed documentation associated with a sample of SSCs to determine j whether the facility properly justified its conclusions. The inspectors determined that the '

l facility had not correctly identified several SSCs that were required to be scoped within the maintenance rule. In some cases, the documentation detailing the technical basis of scoping justifications was not adequate.

l Some SSCs were not appropriately included in scope. For example, the following safety-related SSCs were oraitted: fuel assemblies, fuel handling system, alternate shutdown panel, radiation monitoring panel, emergency lighting battery pack support, and the tunnel under the Service Building. These SSCs were specified as being safety-related in the - l Updated Final Safety Analysis Report (FSAR) for Millstone i in addition, the following non safety-related SSCs were omitted fire protection system,

. post accident sampling system (PASS), seismic monitoring system, communication system and emergoncy lighting system. These non safety-related SSCs met one of the following standards: (1) mitigated accidents or transients; (2) were used in emergency operating procedures (EOPs); (3) whose failure could orevent a safety-related SSC from functioning; or (4) whose failure could cause a scram or safety system actuation. Failure to include ~

these safety-related and non safety-related SSCs in the scope of the maintenance rule represents an unresolved item, pending additional review of scoping during the I maintenance rule baseline team inspection. (URI 50-423/96-09 12)

-In addition, the inspectors determined that additional systems were excluded from the. e C l maintenance rule scope in a questionable manner. Some systems with a small percentage l of safety-related components were not being either included within scope or the scoping decision not being appropriately justified. Specifically, the Integrated Maintenance Program Manual, Rev.1, Program Instruction PI-1.1, " Scoping Phase 1" stated that the Msintenance Engineering Services (MES) Unit Coordinator should review all systems that meet the following criteria

(1) contains safety-related components (CAT 1 in facility terminology) which compose less than 2% of the total system /sub-system population or (2) contains less than four (4) safety-related components. The procedure stated that based on this review, the MES Unit Coordinator could remove systems from the scope based on i the system not being safety-related or being placed with other SSCs. with appropriate ( documentatio The facility had used this process on 11 systen.s containing safety 4 elated components to exclude the system from the scope of the maintenance rule. However, there was no l evidence of appropriate documentation to justify this position. The 11 systems with safety-related components without documented justification were:

Auxiliary Boiler- Auxiliary Condensate Communication- Sound Powered Compressed Gas- Hydrogen

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l Compressed Gas- Nitrogen

! Electrical- AC Lighting- Normal Miscellaneous Primary Water- Primary Water Rad Waste- Liquid and AER Drains Rad Waste- Solid Reactor Coolant- RCP Vibration Monitor Waste Treatment- Waste Water The inspectors noted that all safety-related components must be included within the scope of the maintenance rule program, regardless c,f how tns SSCs are organizad. Therefore, i the facility's inability to address how the safety-related components were being included j within the rule represented a significant compliance problem. The 11 systems with safety- l related components and without a documented justification represent an unresolved item l (URI 50-423/96-09-13), pending further review during the NRC maintenance rule baseline team inspectio Further, the inspectors determined that the facility had in some instances moved SSC component's function (s) from one SSC category to another. The inspectors reviewed a facility provided printout that was used to help identify each category 1 component. This ,

printout listed the following elements in a matrix format: I plant and system name PMMS ID (identification)

l local ID total number of components number of category 1 components safety-related status was the system within scope of the rule Based on a cursory review, the inspectors noted that a number of systems listed in the printout contained safety-related corm nents, but had been determined by NU to be outside the scope of the rule. Further inspection was needed in this area to determine if the facility properly captured these safety-related components within the scope of the rul During the future maintenance rule baseline team inspection at Millstone 3, the NRC will further review this process and how each safety-related component was captured. This review of additional safety-related components represents an inspector follow item (IFl 50-423/96-09-14).

During the review of the facility program implementing the MR, the inspectors noted a tendency to limit the number of SSCs included within the scope of the MR. The inspectors l concluded that the MR scoping process as contained in the Integrated Maintenance l Program Manual was narrowly focused which could have resulted in some of the identified j problems. This approach also appeared to have resulted in weak consideration of the question "Could failure prevent a safety related SSC from functioning?" as required by the Maintenance Rul ,

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46 Conclusions The inspectors identified ,two unresolved items associated with improper scoping. The inspectors concluded that the facility had not correctly identified all of the SSCs that were requ! red to be within the scope of the rule. Five safety-related SSCs and five non safety-related SSCs were inappropriately left out of the scope of the maintenance rule. Also, there were 11 systems with a small percentage of safety-related components that had been excludeo from the scope of the rule without documented justification. In addition, there will be more NRC review of evidence of additional safety-related components that may not have been included within the scooe of the rul M3.2 Safety (Risk) Determination, Risk Rankino, and Exoert Panel I Insoection Scoca (62706) l Paragraph (a)(1) of the rule requires that goals be commensurate with safety. Additionally, ,

the guidance contained in NUMARC 93-01, " Industry Guideline for Monitoring the l Effectiveness of Maintenance at Nuclear Power Plants," specifies that safety be taken into l account when setting performance criteria and monitoring under Paragraph (a)(2) of the rule. This safety consideration would be ueed to determine if the SSCs should be monitored at the system, train or plant level. The team reviewed the methods and calculations that NU had established for making these safety determinations for Millstone i Unit 3. The team also reviewed the safety determinations that were made for the specific l SSCs reviewed during this inspectio )

NUMARC 93-01 recommends the use of an expert panel to establish risk r.ignificance of SSCs by combining probabilistic risk assessment (PRA) insights with operations and maintenarca experience, and to compensate for the limitations of PRA modeling and importance measures. NU used an expert panel to establish risk significance and other maintenance rule related functions. The team reviewed the facilities procedures addressing the expert panel activities and recent expert panel meeting notes. The team also reviewed other expert panel documentation and discussed their decisions with the A plant specific PRA was used to rank SSCs with regard to risk significance. NU replaced its original support state probabilistic safety study (PSS) model with an updated linked f ault tree model in 1995. Data from that new model were used to determine system risk significance. The new model provides analysis of core damage frequency (CDF), that is a Level 1 PRA, where the original model was a full Level 3 risk assessmen The Millstone Unit 3 Individual Plant Examination (IPE) for Severe Accident Vulnerabilities, submitted on August 31,1990 was based on the original 1983 analysis and provided information on CDF and containment failure for both internal and external events. The external events included seismic, fire external flooding and wind damage. The NRC evaluations of the PSS were publisted in three documents: NUREG-1152, " Millstone 3 Risk Evaluation Report"; NUREG/CR-4142, "A Review of the Millstone 3 Probabilistic Safety Study (Level 1)"; and, NUREG/CR-4143, " Millstone 3 PSS, Containment Failure Modes, Radiological Source-Terms and Offsite Consequences." The team referenced these r

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documents along with the PSS and the NRC Staff Evaluation Report (SER) of the IPE in ,

l conducting their review of the risk ranking proces l l

b, Observations and Findinas i I

NU generally followed NUMARC 93-01 guidance in providing their expert panel with '

information on three importance measures, risk reduction worth (RRW), risk achievement worth (RAW), and core damage frequency contribution (CDF). They developed information at the train level that defined the value of RAW, RRW, and appearance in the top 90% of !

I the Level 1 CDF cutsets. NU also calculated the Fussell-Vesely (FV) importance measure of trains. This information was quantified from the recently revised PRA. However, NU l did not quantify containment systems performance or external event data. Therefore, the importance measures did not reflect information on containment performance, large early l release frequency (LERF) sequences, or seismic and fire sequences. However, the team found that some containment systems were included as risk significant by the expert panel which had used the Delphi process to determine risk significanc The Millstone Unit 3 system risk ranking was based on quantified results from the new Level 1 PRA model. Support systems and common cause failures were modeled within the system fault trees. The revised PRA incorporated recommendations previously made ,

during NRC review. These included modeling of safeguards equipment room cooling as support equipment and modeling the total loss of service water as an initiating event.

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i l The team noted that NU has updated the plant specific initiating event frequency to reflect i plant operating experience. However, the PRA used only generic equipment failure data, and NU has not initiated a program to update the model with actual plant equipment dat l

. NU quantified the CDF using a minimal cutset truncation value of 1E-8 per year. The team i found this truncation level to be.relatively high and may eliminate cutsets containing risk ,

significant equipment. in earlier recognition of the effect of this truncation level, NU !

examined the train data for cases where the FV worth was 0.000. For those cases, the

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system basic event was set to " Failed" and the model requantified. The resultant CDF was ;

used to calculate the train RAW. The team noted that in using this technique, RRW '

importance measure was not available for the train. Additionally, this technique may not identify support systems or components that were truncated and potentially risk significan NU did not provide risk significance data for systems important to containment i performance. The team examined the results of the original Millstone PSS and found that the Quench Spray System (OSS) was significant for protecting the containment integrit )

i However, NU had included the OSS as a risk significant system by the expert panel using the Delphi process. Likewise, in considering shutdown risk the expert panel included the following systems as risk significant: the 345 kV system including the main, nuclear i

service and reserve sersice transformers, the station blackout emergency diesel generator, l and the residual heat removal system. The reactor plant component cooling water system was included as risk significant because it provides cooling water to the reactor pump thermal barrier seal coolers, as well as the pump motor oil coolers, the residual heat removal system pump seals, and heat exchangers, and provides emergency make-up water to the charging pump oil cooler purge tank.

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The team found that NU did not consider any part of the fire protection system as within the scope of the Maintenance Rule because it is not used to supply cooling water in normal, off-normal or emergency conditions. However, Section 3.5.2.2 of the IPE which summarizes the effect of external events from the PSS, indicates that the total contribution to the CDF from fira events is approximately 7% of the total CDF. Fires in the charging and component cooling pump zone, cable spreading room, and the control room contribute more than half of the total CDF from fires (Reference: Millstone Unit 3 PSS, Sections 2.5.2.2 and 2.5.2.3). There was no technical basis available to support the decision to exclude the fire protection syste I NU had determined that the calculated risk significance of safeguards room cooling and ventilation equipment (HVAC) was overly conservative because the PRA assumed direct failure of the front line equipment when the associated HVAC equipment failed. This change of support equipment was incorporated within the revised PRA. Because of the modeling assumption, the safeguards equipment rooms' HVAC equipment generally had RRW and RAW wellinto the range to be classified as risk significant. NU had plans to verify their assumption that the modelis overly conservative using an Electric Power Research Institute (EPRI) heat load computation code. During this inspection NU  ;

committed to expediting completion of the calculations. The team observed that several of i the safeguards rooms, including the auxiliary feedwater pump rooms, are smallin size and I l have large heat sources. Therefore, the PRA model assumptions should be verified with

appropriate engineering calculations. This issue will be reviewed during a future inspection

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l Conclusions The team concluded that the PRA level of detail, data, and quality were adequate to l l perform risk ranking. Although the NU process for risk ranking was adequate, the team l observed that the PRA only used generic equipment f ailure data, and that the PRA 1 truncation level was relatively high, allowing the possibility that risk significant equipment was not identified. Additionally, the team noted that the safeguards equipment room ventilation and coolers had been excluded from being risk significant without completing room heat load calculations, and that NU did not use containment equipment or external event analysis in quantifying risk ranking of system U3 M8 Miscellaneous Maintenance issues M 8.1 LQlosed) LER 50-423/96-03:

This LER documented that temporary I-beams were located above several of the recirculation spray system (RSS) heat exchangers for a period of five years. This condition, given a seismic event, could have resulted in the loss of one of the two heat exchangers in each of the two trains of the RSS. This issue was discussed in NRC 1 Inspection Report 423/96-201, and constituted an apparent violation of 10 CFR Part 50, Appendix 3, Criterion XVI, " Corrective Action." This LER is close \

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M8.2 (Closed) LER 50-423/96-18: l i

j This LER documented that N concrete pedestal for the "B" service water system booster ;

bump had been degraded wn:cn rendered the pump inoperable. The pedestal was degraded to the point where it could not be confirmed to meet seismic requirements. The 1

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pedestal for the "A" train was inspected by the licensee and determined to be acceptabl i This issue was discussed in NRC Inspection Report 423/96-201, and constituted an  ;

apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action." This LER is closed.

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U3 E2 Engineering Support of Facilities and Equipment E (Closed) Unresolod item 423/96-08-19: Potential Failure of Solenoid-Ocerated

Valves (SOVs) due to Overoressurization Insoection Scoce (92903)

+This item involved the potential for specific safety-related control valves to fail to operate j properly, due to air supply operation in excess of the manufacturer's maximum operating l

pressure differential (MOPD) rating of the SOVs installed on the control valves. The licensee identified 48 ASCO SOVs that had a MOPD rating less than fulJ air system '

pressure, if the upstream air pressure regulators are non-qualified,f. hen'they could fait resulting in fullinstrument air system pressure being applied to the<SOVs. The solenoid

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MOPD issue had been previously documented in NRC Information Notice (IN) 88-24,

" Failure of Air-Operated Valves Affecting Safety-Related Systems," and Generic Letter (GL)

91-15, " Operating Experience Feedback Report - Solenoid-Operated Valve Problems at '

Reactors." Observations and Findinas l

The licensee had not originally considered this issue as an immediate safety concern since I the SOVs and air regulators were believed to have been purchased as a qualified safety-grade unit; and there were no common-mode failure scenarios identified in the NRC  !

correspondences which could initiate regulator failure. However, recent inspection performed by the licensee revealed that the regulators were not purchased as qualified components. Therefore, in the event of a seismic event and the failure of the air regulators, full air pressure could be applied to the downstream SOVs. This could result in the failure of the SOVs to properly control the air supply to safety-related equipment j-(valves and dampers), resulting in the associated equipment not performing their intended

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safety functions. These include: containment isolation, secondary containment isolation, alignment of tha alternste boration dilution path, and volume control tank level contro :

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No immediate corrective actions were required since the components affected were either l not required for operation in mode 5, or compensatory measures had previously been  !

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taken. The licensee subsequently replaced those SOVs for components required to be operable in mode 5. As further corrective action, the licensee developed a plan to perform

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l 50 a design and installation review of the air system components and configuration. This l includes: (1) performing walkdows.s of installed safety-related air operated components to inspect and document pertinent design and installation information; (2) develop a database from the walkdowns and design information to identify installation and documentation i deficiencies; and (3) initiate adverse condition reports to document and correct allidentified design, installation, and plant documentation problems. This plan is scheduled to be completed by March 3 L 1997. The licensee committed to maintain the plant in Mode 5 or less until the modifications are complete to correct the potential overpressure condition on all of the susceptible safety-related SOV The licensee also performed a review of NRC GLs that did not require a formal written !

response. Twenty-one GLs were identified. These were incorporated into the licensee's i operational readiness plan to be reviewed for applicability to ensure that there are no other operability issues prior to plant startup. The inspector reviewed the licensee's Regulatory ,

Compliance Manual (RCM), Chapter 2, " incoming Correspondence," and verified that it has !

been revised to require that the licensee track and review all NRC GLs for applicabilit ;

The inspector reviewed the list of 48 susceptible SOVs and verified that the licensee had implemented the proper compensatory measures required for mode 5. A review of work orders and a field walkdown revealed that the SOVs for the charging pump cooling I temperature control valves 3CCE*TV37A/B have been replaced with solenoids that had a MOPD rating greater than the full air system pressure. No other components were required for mode 5 operatio The inspector also verified that the other Millstone unit's were reviewing their original response to NRC IN 88-24 to confirm that the database used to identify the potential susceptible ASCO SOVs was correct. Unit 2 had an outstanding action tracking item for this issue. Unit 1 personnel had. generated an engineering work request to review this issu Conclusion The NRC determined that the licensee's initial review and follow up of NRC correspondence was inadequate. A detailed review for potential components affected and of purchase records was not performed to determine the full extent and applicability of the SOV problem. As a result, the licensee incorrectly determined that the ASCO SOVs installed in 15 plant were not susceptible to the MOPD phenomena. As a result, the i safety funct% of 48 components was potentially impacte The instrument air system is not designed as a safety-related system. As a result, the safety-related equipment whose operation requires the availability of instrument air are designed to fail safe on a loss of air or loss of power. However, the failure of the non safety-related pressure regulators could result in the SOVs being exposed to full system air pressure; thus, potentially resulting in improper operation of the specific safety-related control valve The failure of the licensee to establish design controls to verify the adequacy of the design of ASCO SOVs to operate properly when subject to full instrument air pressure is an

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i apparent violation of the requirements of 10 CFR 50, Appendix B, Criterion Ill, " Design Controls." (eel 50-423/96-09-16). Unresolved item 423/96-08-19 is administratively

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i E2.2 (OpenIFl 50-423/96-09-17) Emeraency Diesel Generator Exhaust Stack Insoection Scooe (37551)

The licensee issued a Final Safety Analysis Report (FSAR) change request on April 11, 1995, that removed a licensing commitment to open the emergency diesel generator (EDG)

exhaust access hatch on receipt of a tornado alert. The licensee concluded that the removal of this requirement did not constitute an unreviewed safety question (USO) and therefore prior NRC approval was not required. The inspector reviewed the licensee's safety evaluation and various NRC correspondence to determine if the proposed change was properly handled by the license Observations and Findinas During review of the Unit 3 application for an operating license, questions were raised by the NRC regarding whether the EDG exhaust hatch satisfied the requirements of 10 CFR 50, Appendix A, General Design Criterion (GDC) 2. GDC 2 requires, in part, that structures be designed to withstand the effects of natural phenomena such as tornados j without the loss of capability to perform their safety function '

The EDG exhaust pipes are located outside the EDG building and therefore exposed to j

tornado missiles. Deformation to the exhaust pipe could result in a decrease in the l l operational performance of the corresponding EDG. Prior to plant licensing, the licensee l provided an access hatch in the exhaust duct work, which could be manually opened during a tornado alert and function as an exhaust bypass in the event of tornado missile l damage to the exhaust system. An abnormal operating procedure was generated to ensure that the EDG exhaust access hatch would be opened in the event of a tornado alert. In addition, the licensee committed to open the access hatch annually and inspect for corrosion of parts, and maintain it in an operable status. The NRC considered this to be an j acceptable design; however, questions were raised regarding whether a tornado missile '

could enter other exhaust plenum openings and damage the exhaust pipe upstream of the access hatc '

l The NRC staff stated in a letter dated December 10,1984, that resolution of this concern could be granted if a probabilistic risk assessment (PRA) demonstrated that the probability of significant damage to the EDG exhaust piping due to a tornado missile causing the release of radioactivity in excess of 10 CFR Part 100 limits, assuming a loss of offsite

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power was less that 1x103 per year. The licensee performed a PRA in 1985 and concluded that the probability of significant damage to the EDG exhaust piping from tornado generated missiles would be less than 1x10' per year. The NRC staff reviewed the information in 1985 and concluded that this satisfactorily demonstrated compliance with the requirements of GDC . .

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l 52 l To remove the commitment to open the EDG access hatch, the licensee performed a safety i

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evaluation. The licensee concluded that the propossd change did not constitute an USO ,

based on the fact that the increased probability of damage the exposed EDG exhaust piping during or following a tornado with the exhaust hatches closed was negligible. This conclusion was based on a PRA conclusion that determined that the probability of damage l to either EDG from a tornado missile perforating any wall or roof opening to be 8.7 X 10'

l per year.

During the current inspection period, the inspector discussed the FSAR, safety evaluation '

report, and other licensing documents with NRR personnel. Also, discussions were held

! with cognizant licensee personnel with regard to the basis for the proposed change, and l

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the meaning of an USO.10 CFR 50.59 states that a proposed change shall be deemed to involve an USO if the probability of an accident or malfunction of equipment important to I

safety previously evaluated in the safety analysis report may be increase ,

l The elimination of the procedural requirement to open the access hatch on receipt of a *

l tornado alert does increase the probability, although negligible, of a malfunction of the '

l EDG. It appears the deletion of this licensing commitment is a removal of an original design requirement and therefore NRC concurrence is require .

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I Conclusion

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The determination as to whether this issue was properly dispositioned will be reviewed by I the NRC for technieal adequacy. Continued NRC review of this issue is considered an inspector follow item (IFl 50-423/96-09-17). i E2.3 Adverse Condition Report (ACR) Review Insoection Scooe (37550 and 40500)

The inspector reviewed selected ACRs to assess the effectiveness of the ACR proces The evaluation included an assessment of the root cause determination and whether l appropriate corrective actions were identified and implemented to prevent recurrence of the l adverse conditio '

1 l l Observations and Findinas ACR MP3-96-0467 Fast Transfer Test Failures During testing of the fast transfer function for the 4.16 kV and 6.9 kV electrical buses the following two failures were identified:

e the feeder breaker from the reserve station service transformer to non-safety bus 35C (6.9 kV) failed to auto-close during the test, and e power to safety-related 120 Vac bus VIAC-1 was lost.

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The inspector reviewed the licensee's assessment of the cause of the failures and the corrective actions take The cause of the bus 35C feeder failure to close was found to be due to a high resistance contact (52bb) in the 35C feeder breaker from the normal station service transformer (NSST). During the fast transfer, when the NSST feeder breaker opens, its 52bb contact closes and completes the closing circuit for the Reserve Station Service Transformer (RSST) feeder breaker. The high resistance contact was replaced and retested satisfactoril Bus VIAC-1 is one of four,120 Vac buses each of which are normally powered from their associated safety-related inverter. The inverters normally receive dc power from a rectifier circuit fed from their associated 480 Vac safety bus or from their associated 125 vdc bu During maintenance the 120 Vac buses can also be powered from a 120 Vac regulated power transformer through a manual bypass switch at the inverter. Bus VIAC-1 was in a maintenance lineup at the time of the test; and during the fast transfer a fuse blew in the regulating transformer circuit. Since plant technical specifications specifically require the 120 Vac busses to be powered from their associated inverter, a blown fuse when in the maintenance lineup would not result in the loss of a bus required by technical specifications to support plant operation To preclude the blowing of fuses during fast transfer testing, the test procedure is being changed to ensure that the inverters are in a normal lineup, i.e. on a de supply. Inverter performance has been satisfactory with the test performed in a normal lineu q The inspector verified that the ACR has been included in the licensee's restart list. This item is considered complet ACR 1895 (LER 95-011 Inadvertent Containment Deoressurization Actuation (CDA) Sianal j Durina Valve Maintenance i On April 16,1995 a CDA signal was inadvertently generated during work on a motor operated valve in the recirculation spray system (RSS). The licensee performed a root cause analysis and concluded that the cause of the CDA signal was grounding of a lead during valve work in conjunction with an existing ground on the 120 Vac control circuit (an ungrounded system). The work order included the following caution note "lNHIBIT CDA SIG PRIOR TO WORK." However, neither the operations department personnel or the work group verified that this had been accomplished. The licensee's investigation also found that the workers did not properly verify that the wires were deenergized and noted that if they had checked each of the field wires for a potential to ground the energized lead would have been identifie Corrective actions taken by the licensee included the following:

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e briefed personnel regarding awareness of notes and precautions on work orders and on the proper methods for verifying circuits are deenergized;

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i e issued procedure OP 3250.468 to provide specific direction for disabling the CDA

signal; e' changed the precaution on the work order to " VERIFY OPS HAS HAD I&C BLOCK

'CDA' INTERACTION 1.A.W. OP 3250.46B PRIOR TO STARTING WORK.";

e established a preventive maintenance task to check the 120 Vac control systems for grounds; and, e attached warning labels to valve limit switch covers and breaker cubicles to warn

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workers that removal of the covers or work on the breaker could result in an ,

inadvertent CD The inspector found that the root cause analysis and corrective actions were narrowly focused on the cause of and corrective actions necessary to prevent another inadvertent CDA actuation. A similar event occurred in 1990 (LER 90-002) resulting in the addition of the note on the work order to disable the CDA. The inspector concluded that the root cause analysis did not sufficiently address the implications of inadequate safety taggin The inspector noted that for both events, a more thorough circuit review and a proper safety tagout would have prevented the CDA actuations, and equally important, would have ensured safe work conditions. The corrective actions did not place sufficient emphasis on the fact that worker safety was jeopardized by the inadequate tagout, and the human performance aspects of ignoring cautionary notes and verifying deenergize circuits. This is another example of a narrowly focused corrective action program (See Inspection Report 96-04). Conclusions The inspector concluded that the questionable quality of the root cause investigations and !

corrective actions associated with the 1995 event and ACR 1895 followup represent  !

another example of past implementation of an inadequate corrective action program. This ,

concern has been previously discussed in NRC inspection report 50-423/96-04. The NRC l has indicated that prior to the startup of any of the Millstone units, the corrective action l program must be demonstrated to be effectiv U3 E8 Miscellaneous Engineering issues E (Ocen) IFl 50-423/95-44-06: Service Water Backwash Line Freezing Insoection Scoce (92903)

On January 8,1996, Millstone Unit 2 experienced a problem in which the service water strainer backwash piping froze to the extent that an ice plug formed in a common line that resulted in the inability to backwash the strainers in both service water loops. The inspector reviewed the licensee's evaluation of the Unit 3 intake structure for similar condition .

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55 Observations and Findinas The licensee's review concluded that Unit 3 was not susceptible to a similar freezing event because the b!owdown piping was continually sloped to the discharge point and a blowdown of the strainers occurs at a maximum of every eight hours. The periodic blowdown would melt any ice accumulatio The inspector reviewed the Unit 3 service water system design and operation relative to similarities and differences to the Unit 2 system to assess the potential for freezing of the Unit 3 piping. The inspector noted the following:

• The Unit 2 piping initially froze in a short horizontal run of piping where it exited the intake structure. The source of water that froze was seat leakage from the l

blowdown control valves. The hori70ntal run of piping was then removed and the '

resultant discharge piping configuration consisted of a vertical run of piping inside the intake structure wall that terminated with an elbow that directed the discharge out through an opening in the wallinto the soun !

• Subsequent to the removal of the horizontal piping, significant ice buildup again occurred at the discharge point. The inspector noted that this freezing occurred even though the pipe run was vertical and the piping, except for the discharge point, was located inside the heated intake structur * The Unit 3 service water system is designed with a separate blowdown line for .

each service water train. The piping for each blowdown line is sloped to the )

, discharge point. Each discharge pipe passes through the intake structure floor into the air space above the water intake and then, after a horizontal run, passes i through the intake structure support wall and discharges into the sound several feet l above the water level. This results in the discharge point being exposed to the outside environmen l'

• Leakage was observed through the blowdown control valves in both train Conclusions The inspector concluded that the licensee evaluation did not adequately address the potential for freezing in the backwash line based on the following:

• The experience at Unit 2 following removal of the horizontal piping run indicates that sloping the piping may not prevent ice buildup. Also, the freezing occurred at I temperatures that were not the lowest that could be experienced at this sit * The Unit 3 design results in a length of piping being exposed to cold temperatures prior to reaching the discharge point allowing the water to be chilled when it reaches the discharge point which is directly exposed to the environment.

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• The existing leakage rate past the control valves may provide sufficient continuous flow to prevent freezing. Future valve maintenance that results in a lower leak rate may result in a condition more conducive to ice plugs formin * The piping is not easily accessible so that if ice was to form it would be difficult to access to tha !

The inspector noted that since there are separate blowdown lines for each service water l train, the probability of a common cause failure of service water to both trains due to j freezing is reduced. During the inspection, the licensee decided to change the times !

between automatic blow downs to four hours which should further reduce the potential for

! freezing. However, a documented technical bases for why this action alone would be sufficient to prevent freezing was not provide The inspector also noted that the licensee had calculations that showed there should not be a concern with gage line freezing in the intake structure in the event room heating was ;

lost. (Gage line freezing was an additional concern identified at Unit 2.) l This item remains open pending further licensee evaluation of the issue and NRC review of the adequacy of the technical bases for the final resolutio E.8.2 (Closed) LER 96-030: Nuclear Instrumentation Channels Not Tested in Accordance With FSAR Requirements Section 7.2 of the Final Safety Analysis Report (FSAR) states that the nuclear instrumentation power range channel testing will be performed by superimposing a test signal on the actual detector signal being received by the channel at the time of testin This would maintain the channel operable during testing. However, the test has been performed by disconnecting the channel input cable during the testing and using only a test r gnal to generate the channel trip. The licensee plans to revise the associated test procedures to perform the tests as stated in the FSAR prior to entry into the startup mod The procedure revisions are being tracked in the licensee's restart punchlis CFR 50.55a(h) requires that plants with construction permits issued after January 1, 1971 meet the requireroents of IEEE standard 279, " Criteria for Protection Systems for Nuclear Power Generating Stations." The disconnecting of the cable results in a bypass of the channel without annunciation in the control room contrary to the requirements of IEEE Standard 279."

The safety implications were reduced by the following:

• The out of service time was not significant relative to that allowed by the plant l technical specifications. The plant technical specifications permit a channel to be l inoperable for up to six hours before it is required to be placed in the trip conditio Surveillance tests could routinely be performed in less than approximately 30 minutes.

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e The trip logic is a two out of four cnannels and therefore the protection system l would initiate a trip with one channel under test and the single failure of another channe * The plant has never experienced a high power condition during any of the calibrations.

l This licensee identified and corrected violation of 10 CFR 50.55a(h) is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. This LER is close E.8.3 (Closed) LER 96-22: Emergency Diesel Generator (EDG) Control Panel Noncompliance with Seismic Design Basis On July 22,1996, the licensee discovered that the EDG control panel door latches were not engaged and two latches were broken. The f ailure to secure the doors properly could have resulted in the misoperation of electrical relays and switches during a seismic event.

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The door latches were repaired and secured and engineering prepared written guidance for j generic seismic inspection criteria for plant equipment and components. The seismic requirements were communicated to the plant departments that work on the control panels and affected procedures were to be revised to address the latche Subsequent to the issuance of this LER, the EDG system engineer found severallatches that were not properly secured. This finding was a result of a heightened awareness of the event described in the LER. The licensee documented this event in ACR M3-96-1182 and the operations manager added a note to the shift turnover report regarding the need to ensure the latches are made up properly. Also, the system engineer was taking actions to install signs on the doors to emphasize the need to secure the latches prop erl This failure with regard to panel door latching practices constitutes a violation of minor significance and is being treated as a non-cited violation, consistent with Section IV of the enforcement policy. This LER is close E8.3 (Closed) LER 50-423/96-05 and suoolement 1: The service water booster pump automatic start feature was disabled due to a design control weakness. This issue was discussed in NRC Inspection Report 423/96-201, and constituted an apparent violation of 10 CFR 50.59. This LER is close IV Plant Support (Common to Unit 1, Unit 2, and Unit 3)

R1 Radiological Protection and Chemistry (RP&C) Controls l

l R Radioloaical Environmental Monitorina Proaram (REMP) Insoection Scooe (84750)

The inspe: tor observed and asnessed the licensee's capability to irnplement the radiological environmental monitoring prog 6am (REMP). The prog am was inspected against Sections l

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E.1 and E.2 of the REMODCM, the Regulatory Guide 4.1, " Programs for Monitoring l

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Radioactivity in the Environs of Nuclear Power Plants," and the Updated Final Safety Analysis Report (UFSAR). Observations and Findinas The Radiological Assessment Branch (RAB) continued to maintain oversight for the implementation of the REMP, including overall responsibility for quality assurance oversight within the program and most meteorological monitoring program responsibilities. Members of the Production Operations Services Laboratory (POSL), had the responsibility to implement collection of samples of environmental media such as water, soil, fish and airborne particulates. The environmental samples were prepared and sent to the contractos, Yankee Atomic Environmental Laboratory, for routine analyses. Other responsibilities of the' POSL included exchanging and reading environmental thermoluminescent dosimeters (TLDs) and calibrating and maintaining the air sampler The inspector visited the POSL and examined selected sampling stations to determine whether samples were being obtained from the locations designated in the REMODCM and whether air samplers were operable and calibrated. The sampling stations included air samplers for particulate and airborne iodine, milk sampling stations, the composite water sampler located at the discharge, and a number of thermoluminescent dosimetry (TLD)

stations for direct ambient radiation measurements. All air sampling equipment at the selected locations was operational since the previous inspection. The observed air sampling equipment was well maintained, and the associated air volume measurement '

equipment was in calibration at the time of the inspection. Milk samples were available and the TLDs were placed at locations designated in the REMODC The inspector reviewed the licensee's TLD program conducted at POSL. Overall, the - I program was acceptable. However, the inspector noted that the ionization chamber *

I (condenser R-meter) used to verify operability of the Shepherd panoramic irradiator and ensure thermoluminescent dosimeters are accurately irradiated, had not been calibrated i since 1988. Procedure ES #142, "Thermoluminescent Dosimeter Irradiation" requires a l calibrated ionization chamber be used to verify the calculated dose rate after exposure of I the TLDs. The procedure states in line 2, " Place a calibrated ionization chamber which is fully charged (accuracy i 5% traceable to NIST)in one of the designated locations on the source table. This chamber will be used to verify the calculated dose rate after the exposure." Also, the procedure does not indicate a calibration frequency, however, the vendor manual recommended an annual recalibration. The ionization chamber which was used (Victoreen Condenser-R Meter) had not been calibrated since 1988 to verify its accuracy as traceable to NIST. The inspector noted that Technical Specification 6. requires procedures to be established, implemented, and maintained for activities referenced in Appendix A of Regulatory Guide 1.33, " Quality Assurance Program Requirements" (Operation), Revision 2, February 1978 (RG 1.33). Item 8.a. of Appendix A l to RG 1.33 recommends, in part, that procedures for control of measuring and test equipment and for surveillance tests, procedures, and calibrations be provided to ensure tools, gauges, instruments, controls, and other measuring and testing devices are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy. Failure to use an ionizetion chamber which had been calibrated as required by Procedure ES #142 to verify operability of the Shepherd panoramic irradiator and ensure TLDs were accurately

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irradiated constitutes a violation of TS 6.8.1. (VIO 50-245/96-09-18,50-336/96-09-18, I 50-423/96-09 18)

The Land Use Census required by the REMODCM was conducted with Procedure RAB B-7, )

" Environmental Sample Location Census". The census, performed in 1995, detailed garden and milk locations within 5 miles around the site. The results confirmed milk from cows was unavailable and goat milk was available. Changes in the REMODCM to reflect {

l these findings were in accordance with TS 6.13, " Radiological Effluent Monitoring and l Offsite Dose Calculation Manual (REMODCM)". The results were published in the annual 1 REMP report. The census for 1996 had been recently performed, therefore, the results j were preliminary. The finalized results are to be published in the REMP report for 1996.

l The inspector also reviewed the wind direction (wind roses) and D/O values from the past j

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nine (9) years to detect changes, if any, in the prevalent and least prevalent wind i directions to verify the control stations are stilllocated in the least prevalent wind direction. As a result, the controls were stillin the least prevalent wind direction. This information is very important in maintaining background or baseline data and signifies that calculations performed during preparation remain vali Conclusions l

Overallimplementation of the radiological environmental monitoring program was very good. The program was performed adequately based on the above program review, discussions with the responsible individuals, and review of the REMODCM and UFSA However the observed inconsistency and associated violation indicated a need for thorough l review of the thermoluminescent dosimeter irradiation procedure and enhanced attention to

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the TLD program.

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i R1.2 Meteorofoaical Monitorina Prooram (MMP) Insoection Scoce (84750)

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l The inspector observed and assessed the licensee's capability to implement the

meteorological monitoring program (MMP). The MMP was inspected against Section

! 3.3.3.4, Table 3.3-8 of the TS for Unit 2, Regulatory Guide 1.23, and the UFSAR. The l following areas were reviewed to determine whether meteorological instruments and l equipment were operable, calibrated, and maintained:

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Calibration procedures and the results from 1995 through 1996 1

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Software upgrade for meteorological data acquisition

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Surveillances and preventive maintenance of backup emergency generator to the Main Meteorological Tower l Observations and Findinas

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Calibrations were performed quarterly and records were reviewed for frequency and acceptance. The instruments were traceable to NIST. The Unit 2 TS required semi-annual l calibration and no evidence of missed calibrations was noted. The results were within acceptance criteria. Maintenance of the tower instrumentation was the responsibility of

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POSL. When a sensor appeared to be suspect, the POSL group assessed the situation and ;

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The licensee upgraded the data acquisition computer program EDAN 2 to EDAN 3 which enabled POSL, corporate, the control rooms, and the meteorologist at the Berlin office to l monitor instrument output from several locations. The data acquisition is now PC-based l and is easily accessible. This upgrade is considered beneficial to POSL and aids in their l

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efficiency to repair or replace instrument I

! The Operations Department performed a test each month to verify operability of the l backup emergency generator. The test was not required by TS, however the test was l l performed according to procedure SP 699, " Meteorological Tower Generator Monthly l l Test". The maintenance department performed preventive maintenance (also not required l l by TS) at frequencies that cepended upon specific tasks. The inspector reviewed preventive maintenance (PMs) work orders and monthly test data from November 1995 i

through November 1996. The tests and PMs were performed at the frequencies specified I

and the results were generally within acceptance criteria established in the procedure Conclusions Based on the above review, direct observations, discussions with personnel, and examination of procedures and records for calibration of equipment, the inspector determined that: (1) calibrations and maintenance of the equipment were performed according to the procedures, (2) system reliability was high, (3) initiatives to upgrade the EDAN software were very good, and (4) preventive maintenance of the backup generator was performed according to procedure. The licensee continued to effectively implement the program in accordance with UFSAR commitments, TS, and RG 1.23 recommendation R2 Status of Radiological Protection and Chemistry Facilities and Equipment R Radwaste Ma_terial Condition Corresoondence Discreoancies On November 1,1996, the licensee initiated ACR M1-96-0774, documenting inaccurate statements in a letter from NU to the NRC (Letter B154600) dated December 13,199 The letter discusses the material condition of the Radweste Facilities at Millstone. The letter was in response to a request for additional information from the NRC in a letter dated November 13,1995. The NRC staff requested that NNECO provide a written response that described the root cause(s) of the identified problems in the radwaste facilities.

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"Upon determining the degree to which the material conditions had deteriorated, an Adverse Condition Report (ACR) was initiated to document the findings. The ACR was assigned a significance Level B, thus requiring a root cause analysi The results of that investigation concluded that the present conditions of the radwaste facility are a direct result of lack of management attention. The basis for this determination is numerous memoranda written by NNECO staff and senior leve)

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management over the past several years directed to the Unit and Unit Engineering management requesting attention to the existing material condition In addition, a secondary cause is an apparent absence of ownership for the radwaste systems from an operating, engineering, and maintenance perspectiv Put simply, no single individual or group was in charge of the radwaste facility."

Contrary the above statements, the licensee identified that the only level "B" ACR on this issue was ACR 002372, dated January 18,1996, which documented that the general material condition of the Unit 1 liquid radwaste facilities were in an unacceptable stat This was one month after the December 13,1995, letter. Additionally, the root cause evaluation associated with ACR 2372, which was performed by an event review team and completed on March 8,1996, reaches conclusions somewhat different from those in the December 13 letter. The event review team concluded that during the 1980s and early 1990s, the Nuclear Group had a management driven culture which accepted low standards due to narrowly focused goal The inspector concluded that this is an additional example of the apparent violation (eel 50-245/96-09-19) of 10 CFR 50.9(a), which requires information provided to the NRC by a licensee to be complete and accurate in all material respect R5 Staff Training and Qualification in Radiological Protection and Chemistry Insoection Scooe (83522)

A region-based specialist inspector reviewed the qualifications of the four radiation protection managers designated by the licensee on October 1,1996, to serve in each of the units and in the work support organization. The inspector also reviewed the licensee's technical training program for radiation protection personne Observations and Findinas On October 1,1996, the licensee designated four individuals to serve as radiation protection managers (RPMs), one each in the three units and a fourth in the work services organization. Plant technical specification 6.3.1 for each unit requires that the person designated RPM meet or exceed the qualifications of USNRC Regulatory Guide 1.8, Rev The inspector rewawed the resumes of each of the three unit RPMs, and determined that they met the requirements of this technical specification. Additionally, although not covered under any existing plant technical specification, the inspector also determined that the RPM for the work services organization also would meet this requirement, if applicabl The inspector noted, however, that the documentation and analysis of the qualifications of the RPMs was not performed by the licensee staff until the week just before the specialist inspection, approximately eight weeks after designating the individuals to serve as RPMs.

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One of the RPMs did, however, write an adverse condition report (ACR) documenting this issue, and at the time of this inspection, the licensee was reviewing the reason for the

, delay in verifying the qu'alifications of the RPMs.

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Training being conducted in the fourth quarter of 1996 included emergency response l training, with special emphasis of handling contaminated injured personnel. The inspector reviewed the lesson plan for this training program and determined it to be comprehensive !

and well documented. The inspector reviewed the schedule of technical training that has been developed for the radiation protection staff for 1997. For the first quarter of 1997, a training program based on preparing personnel for the National Registry of Radiation Protection Technologists (NRRPT) examination will be given. Although a number of technicians have already taken and passed the NRRPT examination, this review is being i presented as a "back-to-basics" training for all radiation protection technicians. Plans for additional training during the remainder of 1997 have not been developed. Discussions with the technical training staff indicated that this was due, in large part, to the potential for significant program changes needed to properly support the new radiation protection 1 organizations present at Millstone, and the changing program at Connecticut Yankee. One i contractor (a former senior radiation protection technician at the site) has been hired on a part-time basis to aid in implementing the technical training program in this area. However, two of the four full-time training instructors in this area are on temporary assignment in management positions, leaving a limited staff to develop new training program I l

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The licensee selected fully qualified personnel to serve in the four designated RPM positions. The technical training program in this area continues to develop effective training programs, however there currently exists a manpower shortage in this are R6 Radiological Protection and Chemistry Organization and Administration Insoection Scone (83522)

A region-based specialist inspector reviewed the organizations implemented on October 1,1996, for radiation protection at each of the units and site-wide. Inspection focus included staffing levels, especially in work control and maintaining occupationa' '

exposures as low as is reasonably achievable (ALARA). j R6.1 Manaaement Controls Insoection Scone (84570)

The inspector reviewed organization changes and the responsibilities relative to oversight of the REMP and MMP, and the Annual Radiological Environmental Monitoring Report to verify the implementation of Section of the T Observations and Findinos There were no major changes in the organization and responsibilities pertaining to oversight of the REMP and MMP since the previous inspection, conducted in February 1995. RAB moved from the Berlin office to the Millstone site. For six months, RAB was moved to a different section and

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then moved back to its oriDi nal section. During the six months, the licensee !

continued to implement the REMP and MMP effectively. The responsible personnel cognizant in these programs remained the sam The Annual Radiological Environmental Monitoring Reports for 1894 and 1995 provided a comprehensive summary of the results of the radiological environmental surveillance activities for the report period including a summary of the results of analysis of all radiological environmental samples and environmental radiation measurements taken from locations specified in 3 the REMODCM. The reports also provided the results of the land use l census, and an assessment of the observed impacts of the plant operation on the environment around the Millstone site. The results of these analyses and measurements were summarized and tabulated in the format of the table in the Radiological Assessment Branch Technical Position, Revision 1 November 197 Program changes were documented in the report. These program changes were discussed with cognizant personnel. The changes included the lack of cow milk sampling farms. However goat milk was available and the licensee planned to collect milk from goats as long as goats were raised in the are The inspector detstmined that the changes continued to meet the intent of the environmental sampling progra Analytical data from 1996 were reviewed for sample frequency and analysis requirements as specified in Section E.1 of the REMODCM. The data indicated no obvious impact to the environment public as a result of plant operation. The reports contained no omissions, mistakes, obvious anomalous results and trend Conclusion Based on the above review, the inspector determined that the licensee implemented very good management control and oversight of the REMP and MMP and effectively implemented Section E of the REMODC R7 Quality Assurance in RP&C Activities R7.1 Quality Assurance Audit Proaram Insoection Scooe (84750)  !

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The Quality Assurance audit and surveillance reports of the REMP and MMP i were reviewed against criteria contained in the Quality Assurance Department procedures, Regulmry Guide 1.33, and Section 6.5 of T !

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The inspector reviewed the following Quality Assurance Audit Report as part ;

of the evaluation of the implementation of the TS audit requirement '

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Quality Assessment Services (QAS) Audit Report, Audit N ;

A25106/A24053, Radiological Effluent Monitoring and Offsite Dose i

! Calculation Manuals (REMODCM)-199 i

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'The audit was performed by technical personnel and covered specific areas ,

!- of the REMP and the Radioactive Effluent Control Programs for both the j Millstone and Haddam Neck sites. The inspector reviewed the REMR ]

portions of the audit reports for the Millstone sit ;

i During the review of the audit report and the associated check list, the l inspector noted that the objective of this portion of the audit was to review .j certain sampling locations in the REMP. There were no findings in this are The inspector reviewed the audit plan and audit schedule and determined !

that the audit covered the objectives of the audit plan and was conducted I according to the frequency specified in the T i

- Conclusions Based on the above review, the inspector determined that the audit was '

sufficient to assess the portion of the environmental monitoring program that 1

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had been planned and that the licensee implemented the TS audit requirement I R7.2 Quality Assurance and Quality Control Proarams Insoection Scoos (84750)

The inspector reviewed the quality assurance (QA) and quality control (OC)

programs against Section E.3 of the REMODCM and recommendations of Regulatory Guide 4.15, " Quality Assurance for Radiological Monitoring Programs (Normal Operations) - Effluent Streams and the Environment" to determine whether the licensee had adequate control with respect to 1 sampling, analyzing, and evaluating data for the implementation of the REM Observations and Findinas The inspector visited Yankee Atomic Environmental Laboratory to review the internal OC program, the OA program (internal assessments) and the l interlaboratory comparison program. The OC program included duplicates, l spikes, and exceilent laboratory practices. OC charts were maintained and j reviewed by laboratory personnel to ensure acceptable operation of counting

equipment. The charts indicated that instrument operation was reliable. The

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QA Officer at the YAEL conducted independent audits of laboratory

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operations semiannually. The audits were very methodical and provided very  :

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good insight for improvement where needed. An interlaboratory comparison i

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program was continued using Analytics, Inc. since EPA discontinued the program, with the exception of drinking water,in January 1,1995. The .

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program, similar to the EPA cross-check program, included samples spiked at j

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the appropriate ranges. The spikes were provided to YAEL where the

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analyses were performed. The inspector reviewed the analytical results and

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noted the results were within the licensee's established acceptance criteri t l As a basis for acceptance, Analytics provided the ratio of the observed resuit .i I to the expected result. The laboratory assessed their final resnits and i

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compared them the known value using their own quality control acceptance i

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criteria. This is considered to be a good practice.

i The licensee also continued to send spike and duplicate samples, including  !

TLDs to YAEL as another check on the quality of the laboratory. The

inspector reviewed this aspect of the licensee's QC program and determined 'i 1 it to be very good based on the acceptance of the analytical result The inspector also reviewed the " Semi-Annual Quality Assurance Status  !

Reports" for 1995 and the first half 1996, which summarized the analytical

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results from the blind duplicate (split) samples and interlaboratory program !

' ' Most of the results were within the acceptance criteria. Where discrepancies l

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were found, reasons for the differences were investigated and resolve :

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' Conclusions

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Based on the above review, the inspector determined that the licensee l continued to implement a very good quality control program in accordance with regulatory requirements and that overall quality was ensured through frequent and thorough audit : Observations and Findinas Unit 1 The Unit 1 radiation protection program reports through the Unit Support Services organization to the Unit Recovery Manager. Under the direction of a qualified RPM, the Radiation Protection Department is divided into two working groups. The decontamination group and field radiation protection technicians are under the direction of the Assistant Radiation Protection Supervisor. Personnel in work planning, ALARA and staff health physicists are under the direction of a Technical Services Supervisor. Additionally four

. radiation protection technicians, at the time of the specialist inspection, were on special assignments within the plan The inspector noted the addition of two work planners to the department staff. Their function, as discussed by the inspector with the designated Technical Services Supervisor, was to aid in work planning and ALARA. Under a recently implemented work planning

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process, all work planning, except emergent work, is planned and conducted based on a thirteen week planning schedule. Thework planners from the Radiation Protection  ;

c. Department are in place to identify all work that is scheduled to be performed in the radiologically controlled areas (RCA), and to ensure that this work is assigned a radiation work permit (RWP) and evaluated by the ALARA staff to ensure appropriate ALARA planning, as needed. A unit ALARA program is also under development, and willinclude-senior unit department managers as part of the ALARA planning proces Unit 2 '

l The Unit 2 organizational structure was not finalized and approved at the time of the specialist inspection. Discussions with the unit RPM indicated that the proposed organization had the Radiation Protection Department reporting through the Unit Director to I l 'the Unit Recovery Manager. Within the Department, the RPM proposed establishing three i direct reporting organizations, one each for ALARA, decontamination, and health physics )

! operations. The latter two groups would be headed by an Assistant Radiation Protection i l Supervisor, while the first would be led by the ALARA Coordinato I c. Additional focus on ALARA and work planning was evident within the unit. Daily unit goals for ALARA were now being implemented and discussed at the daily management imeetings. The Recovery Manager had directed the RPM to create a program for ALARA to e include a unit ALARA Committee to be chaired by the Unit Director, and to include the j

f directors of each major department. Additionally, each department is to designate an

'ALARA coordinator to serve as a single point of contact for the unit ALARA Coordinato The inspector also discussed with unit personnel the recently implemented program for self-assessment. Recovery management personnel stressed the importance of having qualified station and site personnel perform back-shift walkdowns of the unit, and having the results of these walkdowns discussed with the Recovery Manager, and presented to unit management. Also being stressed is the raising of unit performance standards as part of this self-assessment program. . A focus on radblogical. work and ALARA practices is i included in this self-assessment effor Unit 3 The inspector reviewed the recently approved management organization in radiation protection at Unit 3. The Unit RPM reports through the Maintenance Director to the Unit Director. The Unit Director, in tum, reports to the Recovery Manager. Within the Radiation Protection Department, an Assistant Radiation Protection Supervisor is responsible for the field and special team health physics technicians, while tbc ALARA coordinator has been assigned two work planners. In addition, two RarMogical Engineers reporting directly to the RPM are also included in the organization.

The inspector discussed with the RPM the recent focus within the unit on improved work ,

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planning through the development of an integrated work order process. Under the program l being developed, work orders will be readily identified and available to both the radiation protection technicians and the ALARA planners wellin advance of the start of work, to aid in the inclusion of appropriate radiological controls. The work order willinclude detailed

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information of RWP controls, ALARA controls and other pertinent radiological informatio Management has also placed significant attention on adherence to the work schedule. A detailed work schedule for the recovery of the unit in 1997 is scheduled to be released prior to the end of 1996. Unit ALARA goals for 1997 will be based on this work i document. The RPM also discussed with the inspector the development of enhanced radiological worker training within the unit. This training is based, in part, on similar !

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programs reviewed by the unit radiation protection staff during visits to other nuclear

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Site Sunoort The site support health physics group is under the direction of an RPM who reports i

through a Director to the Vice President - Work Services. Under the RPM are the self-directed work group, who support the Waste Services Department; a Radiation Protection Supervisor and support group which provides instrument calibration and dosimetry services 1 to the site; the Northeast Utilities Dosimetry Laboratory, which is the National Voluntary Laboratory Accreditation Program (NVLAP) approved dosimetry processor for the site; a -

Radiological Engineering /Ouality Assurance group of engineers formerly part of the Radiological Assessment Branch; and a Radiological Engineering Supervisor and group .

available for program support and special projects. The duties and responsibilities of the site health physics organization was still under development at the time of th:2 specialist inspection. Site-wide support functions such as dosimetry services, instrument calibration, ;

and Waste Services support are carried over from the old organizational structure. The l services to be provided by the two radiological engineering support groups will depend, in ;

large part, on the needs identified by the individual units for technical suppor l Conclusioils Unit 1 Unit 1 has established a viable organization for radiation protection. Significant manpower additions have been made in the work planning /ALARA area to support improved work control in the RCA. The effectiveness of this organization will be reviewed once significant radiological work resumes within the uni Unit 2 Unit 2 has proposed a viable organization for radiation protection. Management attention on the establishment of an aggressive ALARA organization, including the establishment and tracking of daily ALARA goals, and the development of a self-assessment program for the unit which includes radiation protection issues, is a significant improvement in this program area.

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Unit 3 has established a viable organization for radiation protection. Significant attention has been placed within the unit on work planning and work schedule adherence. The

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ef fectiveness of these initiatives will be evaluated once radiologically significant work e resumes within the uni Site Suooort The site has established an organization to continue to provide dosimetry, instrumentation and other support functions to all three units. The activities of the radiological engineering groups has not been finalized, howeve P2 Conduct of Emergency Preparedness Activities P (Closed) Insoector Followuo item 50-245, 336,423/95-36-01: Emeraency -

Preoaredness Annual Exercise Scope This inspection involved the observation of the Millstone Unit 2 partial participation exercise that occurred on November 21,199 i Observations and Findinas )

IThe inspector observed the performance of the exercise from the simulator control room  !

(SCR). The simulated exercise scenario involved a tube leak in the #1 steam generato The SCR crew correctly identified, classified and declared the event using the appropriate Emergency Action Levels in a timely manner. Also, the SCR crew communications regarding the need for various repair teams from the Operations Support Center were goo *Unlike the previous annual exercise, a review of licensee information indicated that the p OSC repair teams were dispatched in a timely manner. Inspector Followup item (IFI) 50-

' 245, 336, 423/95-36-01 discussed that during the 1995 exercise, dispatching one of the three repair teams was delayed for 95 minutes. The four repair teams during this exercise were dispatched in 14, 20, 25, and 26 minute The inspector had the following observations:

• The role of the Shift Technical Advisor was not well defined and other members the emergency response organization were not sure how to interface with him. The STA spent most of his time performing miscellaneous tasks, such as occasionally answering the phone, which distracted from his primary function of plant monitorir * The Shift Manager spent mor+ of Ns time actively doing something or communicating with various mc' 701, allowing him minimal opportunity to fulfill his monitoring role. Discains with the licensee indicate that simulator training and emergency plan training are conducted separatel During a simulator training, emergency plan implementation includes only event classification, allowing the Shift Manager ample opportunity to step i back and monitor the plant and operating crew actions. However, this I training does not reflect what occurs during an exercise when there are l

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many additional tasks, which includes interfacing with the other members of the emergency response organization. The licensee indicated they had been considering training enhancements to address this concer Conclusion Licensee corrective actions in addressing repair team delays were effective; IFl 50-245, 336,423/95-36-01 are considered closed. Two areas for improvement noted during the exercise were that: (1) The role of the Shift Technical Advisor was not well defined and; (2) Due to the time opent interacting with the emergency response organize * ion, the Shift Manager had a limited amount of time to monitor overall plant conditions and operator actions. A concern regarding whether to bypass an automatic safety injection actuation is discussed in Section U2.03.1 of this repor P8 Miscellaneous Emergency Preparedness issues P8.1 Millstone Call-in Drill I i Inspection Scone (82701)

Review the licensee's drill objectives and evaluation report of the September 29,1996, l Millstone Station call-in drill. Additionally, evaluate the requirements for staffing of the l station emergency response organization (SERO). l l Observations and Findinas  !

The inspector conducted an in-office review of the licensee's drill objectives and evaluation report. The call-in drill for September 29,1996, had the following six objectives:

(1) demonstrate the capability to promptly notify station on-call response personnel of emergency classifications; (2) demonstrate the capability to initiate and maintain communications between appropriate emergency response personnel; (3) demonstrate the capability to adequately brief additional personnel when utilized; (4) demonstrate the capability to staff the station emergency response organization in accordance with staffing requirements identified in the emergency plan and procedures (30 minutes for responders including dose assessment personnel, 60 minutes for staffing emergency facilities' by primary responders and 120 minutes for support staff);(5) demonstrate the conduct of a l drill between the hours of 6:00 p.m. and 4:00 a.m.: and (6) demonstrate the use of the common operating procedure for severe weather operation The drill was conducted from 6:00 p.m. to 8:30 p.m. on September 29,1996. According to the licensee's drill evaluation report, the simulated Alert was declared at 6:20 p.m. and '

the emergency response notification system (ERNS) was activated at 6:29 p.m. The SERO personnel were required to report to tneir assigned facilities,i.e., the Technical Support Center (TSC), Operational Support Center (OCS) and the Emergency Operation Facility (EOF). The TSC/OSC were declared activated at 7:20 p.m. and the EOF was declared activated at 7:27 p.m. These activations were within the NRC's 60-minute goal for staffing emergency response facilities after notification to emergency responder _

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The drill evaluation identified strengths in command and control exhibited by the Unit 3 shift manager, operations crew and on-shift director of station emergency operations, and timely notifications by the shift technician. A fitness-for-duty issue was identified with regard to one of the responders. It was appropriately handled by station securit . Additionally, several areas for improvement were identified for equipment, procedures, communications, and drill control. The licensee's drill evaluation report indicated that all of the drill comments and areas for improvement were placed in the emergency preparedness

- tracking syste The inspector reviewed the applicable sections of emergency preparedness administrative procedure (EPAP) 1.15, Revision 1, for Millstone Station and Administrative Control Procedure (ACP) 1.0-6, Revision 15, for the Haddam Neck plant to determine if there were adequate controls placed on the assignment of personnel to the SEROs. Both EPAP-1.15 and ACP 1.0-6 have detailed checklists to determine the qualifications of responders for assignment. These checklists ensure that the assignee has completed the required emergency plan and other necessary training, understands the requirements and responsibilities of an SERO member, understands the fitness-for-duty requirements, and lives within an area that enables the assignee to respond within the required time limi Additionally, the procedures require emergency response assignees to stay within an area

--that allows response within the time limit when on call. The inspector also reviewed a memorandum, dated July 21,1995, signed by responsible managers and sent to the SERO staffs for the Millstone Station and the Haddam Neck Plant. The memorandum is explicit in establishing the responsibilities and obligations for the on-call SERO staf Conclusion eBased on review of the licensee's evaluation report, the call-in drill met NRC goals and requirements and the NRC-approved emergency plan commitments. The administrative

procedures for the Millstone Station and Haddam Nock Plant appear to be adequate for ensuring that the established times for staffing the emergency response facilities are me S1 Conduct of Security and Safeguards Activities

S1.1 Review of Local Radio Station Broadcast On October 28,1996, at approximately 6:30 a.m., a local radio station broadcast that an employee had been dispatched to the Millstone site in an attempt to breach securit Licensee security management was made aware of the potential threat by on'3 of its employees who was listening to the radio station on the way to work. A Security Alert was initiated and threat contingency measures were implemented in accordance with the NRC-approved Contingency Plan and site contingency procedures. Appropriate notifications were made to local and state police, the FBI, and the ':H At about 7:30 a.m., the radio station broadcast that its employee was in the plant parking lot. At approximately 8:00 a.m., the radio station broadcast that its employee was in the control room at the site, and at approximately 8:15 a.m. the station broadcast that its employee had left the site and was on the way back to the radio statio __. __ - _. __ _. _ _ -._ - _ _ _ . . _ . _ . _ . . _ _ _ _ _ . - - _ .. . .

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The licensee promptly coracluded that no security breach had occurre A security specialist was dispatched from Region i about mid-day to review the actions implemented by the licensee as a result of the threat. The inspector's review determined that all appropriate actions were properly implemented, appropriate notifications were made in a timely manner, and that appropriate follow-up actions were take On October 30,1996, the licensee confirmed, through discussions with the manager of i the radio station, that the entire matter was a hoax. No one from the radio station had

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been dispatched to the site and the manager committed that a statement to that effect j would be broadcast. That broadcast was made about 6:30 a.m. on November i

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S8 Miscellaneous Security and Safeguards issues S8.1 [ Closed) URI 50-245/96-06-16: Unauthorized Entrv Into the Protected Area Insoection Scone (81700)

The inspectors reviewed the event associated with an unauthorized entry into the Millstone l Station protected area (PA) by an administrative contract person and documented the !

results in NRC Inspection Report 50-245/96-0 Observation and Findina j On August 5,1996, an individual working for an administrative contractor arrived at the station to report for a work assignment. She had worked at the station until July 19, 1996. However, her key card had been deactivated following her termination. She was met by a co-worker after arriving at the access control center. The co-worker saw that the individual was having trouble entering through the access portal and used her own valid key card and hand geometry to allow the individual to enter. The co-worker assumed there was a problem with the turnstile. The co-worker followed the unauthorized individual into the PA by keying in a second time. The two indiv! duals reportedly worked in proximity to each other in the PA for the entire day shif When the individual with the deactivated key card attempted to exit the stat' ion at the end of the shift at about 3:40 p.m., the deactivated key card caused an alarm to which the security force responde Conclusions The inspector concluded that during this event, an individual failed to comply with the licensee's security requirements and conditions of unescorted access authorization. This is a violation (VIO 50-245/96-09-20) of the Millstone Nuclear Power Station Physical Security Plan, Section 6.1 " Access Control."

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V. Manaaement Meetinas i

X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on January 7, and 9,1996. The licensee acknowledged the findings presente X1.2 Final Safety Anaivsis Reoort Review A recent discovery of a licensee operating their facility in a manner contrary to the.UFSAR description highlighted the need for additional verification that licensees were complying with UFSAR commitments. All reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures and parameter While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The following inconsistencies were noted between the wording of the UFSAR and the plant  !

. practices, procedures and/or parameters observed by the inspectors, as documented in l Sections U1.06.1, U1.06.2, U1.E1.1, U2.02.1, U2.E1.1, U3.01.1, U3.E2.2, and U3.E l l

Additionally, during the inspection of the maintenance rule program for Unit 3 (Section U3.M3.1), the inspectors noted inconsistencies in the FSAR during the review of Table !

3.7.B.2, " Methods of Analysis used in Seismic Category 1 Structures." The listed seismic l category structures were not the same as indicated in other sections of the FSA '

Also, the inspector verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters, except in the area of the management organization and responsibilities for radiation protection. Section 12.5 of the Unit 1 UFSAR !

and Section 11.2.3 of the Unit 2 UFSAR make reference to Section 12.5.1 of the Unit 3 l UFSAR for a full description of the health physics organization and reporting function This description no longer is accurate due to the restructuring and unitization of the l Radiation Protection Program, as described in Section R6, above. The Work Services l organization recognized the need to update the Unit 3 UFSAR to reflect the management changes and identified it to the Site Licensing Director by memorandum, dated November 29,199 X1.3 Pre-decisional Enforcement Conference A pre-decisional enforcement conference was held between Northeast Nuclear Energy Company and the NRC on December 5,1996. Enforcement actions described in the NRC letter to the utility, date November 13,1996, were discussed. A list of the attendees is provided in attachment .. - _ - - . .. . . - . . - - - _. . - - - .- I

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INSPECTION PROCEDURES USED ,

IP 37551: Onsite Engineering-i IP 40500: Licensee Self-Assessments Related to Safety issues inspections l IP 61726: Surveillance Observations

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IP 62706: Maintenance Rule Inspection Procedure IP 62707: Maintenance Observations

IP 71001: Licensed Operator Requalification Program Evaluation

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IP 71707: Plant Operations IP 81700: Physical Security Prograrn for Power Reactors IP 82701: Operational Status of the Emergency Preparedness Program  ;

IP 82522: Radiation Protection, Plant Chemistry, Radweste, and Envir , mental:  ;

Organization and Management Controls 17 84750: Radioact!;c Waste Treatment, and Effluent and Environmental Monitoring l

lP 92700: Onsite follow-up of Written reports of Noorostine Events at Power Reactor j Facilities IP 92901: Follow-up Operations IP 92903: Follow-up Engineering

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l 74 ITEMS OPENED, CLOSED, AND DISCUSSED

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Ooened eel 245/96-09-01 U1.0 Timeliness of Reportability Assessment eel 245/96-09-02 U1.0 Qualifications of Unit Director URI 245/96-09-03 U1.0 Organizational Changes VIO 245/96-09-04 U1.0 Modified TS Responsibilities eel 245/96-09-05 U1.0 QA Report Corrective Action Not im eel 245/96-09-06 U 1.M RCPB Piping IGSCC/ Structural Inte eel 245/96-09-07 U1.E EDG Air Start Valves '

l eel 245/96-09-08 U1.E GL 89-13 Inaccurate Corresp.

l URI 336/96-09-09 U2.0 EP Exercise Operator Override SIAS I

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NCV U2.M TS Verbatim Compliance eel 336/9t -09-10 U2.E EDG Bearing Failures URI 245/423/

96-09-11 U 3.M Arcor Epoxy Lining Failures l URI 423/96-09-12 U3.M Ommission of SSCP From Scope

URI 423/96-09-13 U 3.M Systems Omitted From Maintenance Rule without Basis

{ IFl 423/96-09-14 U3.M Maintenance Rule Scoping IFl 423/96-09-15 U3.M HVAC Heat Load Modelling eel 423/96-09-16 U3.E Air SOV Over Pressurization IFl 423/96-09-17 U3.E EDG Exhaust Stack NCV U3.E Ni Channels Not Tested NCV U3.E EDG Control Panel Latches VIO 245/336/423 96-09-18 R1.R Failure to Calibrate TLD Survey Meter eel 245/96-09-19 PS.R Radwaste inaccurate Correspondence VIO 245/96-09 20 PS.S Unauthorized Entry into PA Closed Section t 245/96-06-16 PS.S '

245/96-06-03 U 1.M /96-05-08 U2.M /96-08-19 U3.E /336/423 95-36-01 PS.P2.1 l

j Discussed j

423/95-44-06 U3.E8.1

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t The followina LERs were also closed durina this inspection:

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\ DN 50-423 .

i 96-03 .

96-04 96-05 & 96-05-01 l l 96-18

96-22

, 96-25 l '96-30 , l l  !

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LIST OF ACRONYMS USED ACP Administrative Control Procedures ACR adverse condition report AEC Atomic Energy Commission ALARA as low as reasonably achievable ANSI /ANS American National Standards institute /American Nuclear ASME American Society of Mechanical Engineers %

AWO automated work order BWR boiling water reactor  !

CDA containment depressurization actuation CDF core damage frequency CEA control element assembly CFR Code of Federal Regulations

C M common maintenance procedure CRD control rod drive i DRCH Division of Reactor Controls and Human Factors )

DRS Division of Reactor Safety i EAD Events Analysis Department i EDG emergency diesel generator l eel escalated enforcement item EOF Emergency Operations Facility EOP emergency operation procedure i EP Emergency Plan i EPAP emergency preparedness administrative procedure l EPRI Electric Power Research Institute  !

ERNS emergency response notification system ERT event review team  !

ESF engineered safety feature  !

ESW emergency service water i FSAR Final Safety Analysis Report l FSARCR Final Safety Analysis Report Change Request !

FV Fussell-Vesely l GDC general design criterion / criteria '

GL Generic Letter gpm gallons per minute HPSI high pressure safety injection HOMB Quality Assurance and Maintenance Branch ICAVP Independent Corrective Action Verification Program IFl inspector follow item IGSCC intergranular stress-corrosion cracking INPO Institute of Nuclear Power Operators IP inspection procedure IPE individual plant examination ISI inservice inspection JTA job task analysis JPM job performance rieasure LER licensee event report

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LERF _ large early release frequency LNP- loss of normal power LOCA loss of coolant accident MES Maintenance Engineering Services MOPD maximum operating pressure differential MRT management review team I

NGP Nuclear Guidance Procedure NNECO Northeast Nuclear Energy Company NPRDS Nuclear Plant Reliability Data System NRC Nuclear Regulatory Commission

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l NRR Nuclear Reactor Regulation NRRPT National Registry of Radiation Protection Technologists .

NSIC Nuclear Safety information Center i NSST normal station service transformer NUMARC Nuclear Management and Resources Council l NUREG Nuclear Regulation NVLAP National Voluntary Laboratory Accreditation Program OCA Office of Congressional Affairs OD operability determination OP operating procedure OSC Operational Support Center PAO Public Affairs Office

PASS Post Accident Sampling System PDR Public Document Room I PEO plant equipment operator l

PIR plant information report l PMMS planned maintenance management system PORC plant operation review committee PRA Probabilistic Risk Assessment PSS Probabilistic Safety Study QA quality assurance QAS Quality and Assessment Services QSS quench spray system RCM Regulatory Compliance Manual RCP reactor coolant pump RCS reactor coolant system RFO refueling outage l RG Regulatory Guide l RI Region i RPM radiation protection manager RRW risk reduction worth RSS recirculation spray system  !

RSST Reserve Station Service Transformer  !

l RWP radiation work permit i

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SBGT standby gas treatment SCR simulator control room

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SER safety evaluation report l SERO station emergency response organization i

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SFP spent fuel pool [

SlAS safety injection actuation system l SORC site operations review committee i l

i SOVs solenoid-operated valves l l SP surveillence procedure .i

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l SPO Special Projects Office

! SRO senior reactor operator SSCs structures, systems, and components l

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l STA shift technical advisor

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TS technical specifications TSC Technical Support Center UFSAR updated final safety analysis report .

l UIR unresolved indication report  ;

l URis unresolved items USQ unreviewed safety question  ;

i Vdc volts, direct-current i

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t DECEMBER 5,1996 PRE-DECISIONAL ENFORCEMENT CONFERENCE MILLSTONE SIMULATOR l LIST OF ATTENDEES N TITLE l H. Miller Regional Administrator, Region I l D. Screnci Public Affairs Officer, Region 1 J. Lieberman Director, Office of Enforcement D. Holody Enforcement Officer, OE, Region I l

M. Virgilio Deputy Director, Division of Inspection and l Support Programs, Office of Nuclear Reactor Regulation (NRR)

W. Travers Director, Special Projects Office (SPO), NRR W. Lanning Deputy Director of inspections, SPO R. Cooper , Director Division of Reactor Projects (DRP), Region 1 J. Durr Branch Chief, DRP, Region i P. McKee Deputy Director of Licensing, SPO A. Burritt Resident inspectos, Unit 1 l J. Anderson Projects Manager, Licensing, Unit 1 D. Beaulieu Senior Resident inspector (Acting), Unit 2 i D. Mcdonald Senior Project Manager, Licensing, Unit 2 R. Arrighi Resident inspector, Unit 3 V. Rooney Projects Manager, Licensing, Unit 3 T. Eastick Senior Resident inspector, Unit 1 A. Cerne Senior Resident inspector, Unit 3 N11 TIRE B. Kenyon President ano Chief Executive Officer D. Goebel Vice President Nuclear Oversight J. McElwain Millstone 1 Recovery Officer M. Bowling, Jr. Millstone 2 Recovery Officer J. Cowan Millstone 3 Recovery Officer P. Hinnenkamp Unit Operations Director - Unit 1 J. Armstrong Engineering Director - Unit 1 P. Richardson Unit Director - Unit 2 R. Necci Engineering Director - Unit 2 M. Brothers Unit Director - Unit 3

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P. Grossman Engineering Director - Unit 3 l

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