ML20135E616
| ML20135E616 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/24/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135E602 | List: |
| 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) | |
See also: IR 05000245/1996009
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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
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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
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TABLE OF CONTENTS
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EXE CU TIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv t
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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
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U3.1 Operations ................................................. 35 l
U3 01 - Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
U3 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . 36 )
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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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l USM2 Maintenance and Material Condition of Facilities and
Equipment ...................................... 41
U3 M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . 43
U3M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . 48 )
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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
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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
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- The licensee failed to perform a comprehensive evaluation and disposition of
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regulatory requirements to support recent Millstone site organizational changes.
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 issues.
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)
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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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! determined to adequately maintain operability and document the bases for installed
- temporary modifications. (Section U3.02.1)
Maintenance
- At be n :. aix reactor coolant components had an unacceptable structural integrity
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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
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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 violation.
(U 2.M 1.1 )
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- At Unit 3, with the exception of procedure SP 3712NA, " Battery Surveillance
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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 job.
(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
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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 matter.
(U 3.M 2.1 )
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- Numerous safety-related and non safety-related structures, systems or components
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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 50.59.
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. (Section U1.E1.1)
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! * 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)
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 closed. 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 tagging. 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
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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 achievable.
(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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Report Details i
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
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request pursuant to 10 CFR 50.54(f) and Confirmatory Orders.
U1.1 Operations ,
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U101 Conduct of Operations
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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 below. :
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01.1 Refuel Floor Radiation Monitor j
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a. Insoection Scone (71707)
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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 event. l
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b. 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 initiate. 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 indication.
The inspector discussed his concern with the lack of an appropriate operability
( determination, with the Shift Manager, who then requested that a more complete
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operability basis be provided by the I&C department. This assessment was completed,
documented, and reviewed by operations, and found acceptable.
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 !
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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 )
designed.
c. 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
indication.
01.2 Timeliness of Reoortability Assessments
a. 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 safety.
b. 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 50.72.
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During the review of prompt reports for timeliness, the inspector identified five events that
were not appropriately reported.
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 condition.
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
ACR.
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 12,1996.
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 issue.
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 actions.
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
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control rod drive (CRD) seismic qualification as a result of NRC inspection activities.
However, the ACR was dispositioned as a level "D" and no corrective action was taken.
This issue was subsequently addressed in NRC report 50-245/96-08. section U1.E8.4.
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
,
'
determinations. The revised procedure will replace the "NU Reporting Guidance on 10 CFR
50.72 and 10 CFR 50.73" booklet.
c. 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 .
)
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
actions.
U106 Operations Organization and Administration
06.1 Qualification of the Unit Director I
a. 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 station.
b. 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
'
license or possess equivalent."
l
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5
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 challenged.
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 documented.
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 standard.
4
The UFSAR, section 13.1.2.2.1, " Plant Positions and Descriptions," em 2. " Director, !
'
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 license. !
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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 issue.
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 findings.
c. 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 a. 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 changes.
b. 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 changes.
Further, the letter stated that the licensee would request a change to the technical
4
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 officer. 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.
,
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
,
any comparisons or evaluations of the effect of the new organization on previous
( commitments prior to implementation of the changes.
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 manner.
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 issues.
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.
,
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
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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 changes.
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:
6.5.1.6.e Receives report on violations of Technical Specifications from PORC;
6.5.1.7.b Receives notification of disagreement between PORC and the Unit Director;
6.6.1.b Receives copy of PORC review of reportable events;
6.7.1.b 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;
6.7.1.d Notified within 14 days of a safety limit violation.
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 specifications.
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 missed.
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-compliance. '
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 issue.
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 period.
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9
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 change.
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 issue.
c. 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 organization.
In addition, the oversight organization failed to followup and assure proper resolution of l
these issues. 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, reorganization.
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 issues.
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 compliance.
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
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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 a. 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.
! b. Observations and Findinas
1
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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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 performed.
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
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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 review.
Additionally, the inspector noted that no additional corrective actions or recommendations
above and beyond the Nuclear Excellence Plan were made by the ERT.
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 implemented.
c. _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 issues.
U1.11 Maintenance
U1 M1 Conduct of Maintenance
M 1.1 Steam Tunnel Ventilation Radiation Monitor
a. Insoection Scooe (61726)
The inspectors reviewed issues associated with the performance of SP 406W, " Steam
Tunnel Ventilation Radiation Monitor Functional Test and Calibration."
b. 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 signal.
Technical specifications do not require a down scale trip nor specify a setpoint for the
downscale trip.
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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
!
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 drifts.
c. 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 identified.
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 deficiencies.
U1 M8 Miscellaneous Maintenance issues
l
M 8.1 (Closed) URI 50-245/96-06-03: ISI Proaram Review
a. 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 50-245/96-06.
b. Observations and Findinas
!
, 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 geometry.
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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l c. Conclusions i
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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-
,
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
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 violation. l
l
U1.Ill Enoineerina
U1 E1 Conduct of Engineering
E1.1 Diesel Generator Startina Air Svstem
a. 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,
b. 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
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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
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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 valves.
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 internals.
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 warranted. 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
,
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 psig.
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 header. ,
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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 line.
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.
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c. 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 +
E3.1 Inaccurate Corresoondence <
a. Inspection Scone
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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
b. 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.
!
The licensees response A08201, dated 1/25/90, Attachment 2 stated, "The following
program is either in effect or will be implernented."
l
l A. 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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B. Millstone Unit No.1 service water system is continuously chlorinated whenever the I
potential for macroscopic biofouling species exists.
I
C. There are two loops that may fall under the criterion " infrequently used" as defined
.
)
i in GL 89-13. They are the emergency service water (ESW) and the diesel generator
- supply loops. l
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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
.
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.
'
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-up.
!
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 exchanger.
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.
1
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
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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
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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
!
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 existed.
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
2
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."
1
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 24,1995.
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 items.
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
,
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
,
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.
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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 discrepancies.
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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-89-13.
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 assessments. !
c. 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-
!
CFR 50.9(a), which requires information provided to the NRC by a licensee to be complete
and accurate in all material respects.
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
a. Scope
!
The NRC evaluated the timeliness in which the licensee completed corrective actions
associated with Unit 2 adverse condition reports (ACRs).
l b. 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 numbers.
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
!
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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DEPARTMENT ACRs OLDER THAN
120 DAYS -
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Operations 55 l
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Design Engineering 609 l
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Technical Support 56
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l Maintenance and Work 90
l Planning
! Licensing 5 2 '.
Other 78
TOTAL 940-
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l c. 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 restart.
01.3 Reportability Evaluation Form Backloa
a. Scope
The inspector reviewed the backlog of approximately 90 reportability evaluation forms
(REFs) that had not been dispositioned by the licensee.
b. 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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--g ~ + - y- -y,. i-mw- 4 .m w a -
m.*-y ,e - -- y y a**< em- e e. e., .- ...m---4.cy
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inspector, the licensee expedited their review of the 90 outstanding REFs and determined
that none were reportable.
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 necessary. '
c. 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 reports.
01.4 Inadvertent Reduction in Soent Fuel Pool Level
a. Scope
The inspector reviewed an event involving the inadvertent reduction in SFP level.
1
b. 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 draining.
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 event.
As an immediate corrective action, the handwheel from valve 2-RW-148B was removed.
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 SFP.
c. 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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i the event and; (3) the ERT review was comprehensive and their persistence allowed them .
! to identify the root cause which was not readily apparent. I
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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 analysis.
U2 03 Operations Procedures and Documentation
- 03.1 Svoassino Automatic Actuation of Plant Protective Features
a. 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).
b. 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
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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 bypassed. '
c. Conclusion ;
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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
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l a. Insoection Scoce
!
! 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 sampled.
b. 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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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 examinees.
b.3 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 transients.
Although the bank lacked diversity, the scenario sets run met the criteria of the examiner
standards.
c. 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 faileres. j
05.3 Trainina Content
a. Insoection Scooe
The inspectors reviewed lesson plans and feedback mechanisms to verify that plant and
industry events, modifications, and personnel feedback were incorporated into training.
b. 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 effective.
c. Conclusions
The facility has effective mechanisms for modifying training in response to plant and
industry events and other identified needs.
05.4 Examination Administration and Evaluation
a. 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 performance. !
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b. Observations and Findinos
The crew and allindividuals passed their written and operating examinations. Two
individuals failed one JPM each.
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 leak. 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 practices.
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 JPMs.
c. Conclusions
'
Crew performance was good. Performance deficiencies which existed were appropriately
evaluated by the facility, j
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05.5 Remedial Trainina
a. 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
'
instructors, and the observation of remedial training administered during the week the
inspectors were on site.
1
b. 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 provided.
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 training.
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 areas.
c. 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
a. 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).
- b. Observations and Findinas .1
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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
'
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
'
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 method.
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 requirement.
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 50.73.
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c. 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 4.1.2.3.3.
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 reports.
U2 M8 Miscellaneous Maintenance issues
M 8.1 (Closed) Unresolved item 50-336/96-05-08: Procedure Comoliance Durina
Emeroency Diesel Generator Reoairs
a. Insoection Scongt
>
. 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 review. l
.
b. 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.
'
.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 occur.
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
performed.
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 failures.
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c. 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 closed.
U2.lli Enaineerina
U2 E1 Conduct of Engineering
E1.1 Preoarations for Entrv Into Mode 6 - Refuelino
a. 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 6.
b. 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 movement.
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 6.
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 out.
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 schedule.
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 thorough. !
c. 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
identified. I
U2 E2 Engineering Support of Facilities and Equipment
E 2.1 "B" Emeraencv Diesel Generator Failure l
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a. 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 recurrence.
l
b. 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 month. i
For a period of time, the licensee was starting the EDGs once per week due to other i
reliability concerns.
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 crankline.
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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-lubrication.
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 damage.
]
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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 bearing. 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 flashed. '
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:
1
e inadequate oil pressure to the upper bearings resulting in marginal lubrication when l
the engine is started, i
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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;
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- Cumulative bearing damage during fast starting that did not " heal" during short l
unloaded runs, and; l
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- Clearances in the number 8 and 9 upper bearings that were replaced in March 1996 '
were probably tighter than the other bearings.
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
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- Decisions about EDG operation focused primarily on operability rather than reliability
issues.
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
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removal of air from the system.
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
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e Revision of procedures to increase run-in time following bearing replacements.
c. _ 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 failure.
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
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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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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
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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 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 requirements.
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
project.
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 period.
U3O2 Operational Status of Facilities and Equipment
O2.1 Batterv Confinuration and Modification Controls (71707, 92901)
a. 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 place.
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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b. 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 2.
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 485.
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 frame. 1
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 records. ]
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 controls.
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 inspections. 1
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 closed. i
l
,
U3.Il Maintenance >
!
U3 M1 Conduct of Maintenance
M1.1 General Comments
a. 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
b. 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 condition.
-
! in addition, see the specific discussions of maintenance / surveillance activities observed i
under M1.2 and M1.3, below. l
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M1.2 Work Activity Stand-Down
a. 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 material. ;
1
b. 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 craft.
A briefing sheet was provided by the recovery manager for use by each supervisor to !
,
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 success. !
1
M1.3 Service Water Strainer Renair
!
l a. 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
b. 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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40
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 basis.
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 4. 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 sheet.
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 station.
.. . __ - .. -. - - . _ -- - -
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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)
a. 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 coating. )
b. 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
fragments.
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 exchangers.
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
-
delamination at Millstone Unit 1 have also been applied in the field. No delamination has
, been recorded at Unit 2.
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As corrective action, maintenance procedure MP 3710AH, "Arcor Coating," was revised to
stress the importance of maintaining satisfactory environmental conditions during coating
.
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 system. 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
'
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.
l
l
Review of Vendor Information
The inspector compared the Unit 3 maintenance procedure MP 3710AH to the vendor
manual and noted several discrepancies. These included:
!
!
- 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
procedure. 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 operation.
- The final cure times were not exactly stated as those in the vendor manual. ,
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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43
l
already in the process of developing a new Arcor maintenance procedure and had
incorporated some of these items.
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 necessary.
c. 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
a. 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,
b. Observations and Findinas
, NU evaluated 222 SSCs during the initial scoping phase. The facility used the Millstone
!
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
'
tenth of the SSCs were included with other SSCs' functions already within the scope of
the maintenance rule.
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 criteria.
,
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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 functions.
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 3. 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
( documentation.
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 inspection.
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 rule.
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).
1
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 Rule.
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c. 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 rule.
M3.2 Safety (Risk) Determination, Risk Rankino, and Exoert Panel
I
a. 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 inspection.
)
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 them.
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 assessment.
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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47
documents along with the PSS and the NRC Staff Evaluation Report (SER) of the IPE in ,
l conducting their review of the risk ranking process. 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 significance.
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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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 data. 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
significant.
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 integrity.
)
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 system. 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
! (IFl 50-423/96-0915).
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c. 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 systems.
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 closed.
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M8.2 (Closed) LER 50-423/96-18: l
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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
!
pedestal for the "A" train was inspected by the licensee and determined to be acceptable. 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.
l U3.lli Enaineerina !
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U3 E2 Engineering Support of Facilities and Equipment
E2.1 (Closed) Unresolod item 423/96-08-19: Potential Failure of Solenoid-Ocerated
Valves (SOVs) due to Overoressurization
a. 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
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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
!
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 U.S. '
Reactors."
b. 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 control. :
,
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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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 SOVs.
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 applicability. ;
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 operation.
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
issue.
c. 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 impacted.
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 valves.
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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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
3
closed. '
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E2.2 (OpenIFl 50-423/96-09-17) Emeraency Diesel Generator Exhaust Stack
a. 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 licensee.
b. 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 functions. '
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 hatch. '
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
'
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 2.
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l To remove the commitment to open the EDG access hatch, the licensee performed a safety
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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.
1
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
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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 increased.
,
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 required. .
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c. 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
a. Insoection Scooe (37550 and 40500)
The inspector reviewed selected ACRs to assess the effectiveness of the ACR process.
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 condition.
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l b. 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 taken.
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
satisfactorily.
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 bus.
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 operations.
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 lineup. q
The inspector verified that the ACR has been included in the licensee's restart list. This
item is considered complete.
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 identified.
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 CDA.
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 tagging.
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 deenergized.
circuits. This is another example of a narrowly focused corrective action program (See
Inspection Report 96-04).
c. 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 effective.
U3 E8 Miscellaneous Engineering issues
E 8.1 (Ocen) IFl 50-423/95-44-06: Service Water Backwash Line Freezing
a. 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
conditions.
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b. 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 accumulation.
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
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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 sound. !
- 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 structure.
- 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 environment. l'
- Leakage was observed through the blowdown control valves in both trains.
c. 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 site.
- 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 forming.
- The piping is not easily accessible so that if ice was to form it would be difficult to
access to thaw.
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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 provided.
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 resolution.
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 testing.
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 mode.
The procedure revisions are being tracked in the licensee's restart punchlist.
10 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 condition.
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
channel.
- 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 closed.
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 latches.
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 erly.
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 closed.
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 closed.
IV Plant Support
(Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry (RP&C) Controls
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l R 1.1 Radioloaical Environmental Monitorina Proaram (REMP)
a. 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
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E.1 and E.2 of the REMODCM, the Regulatory Guide 4.1, " Programs for Monitoring
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Radioactivity in the Environs of Nuclear Power Plants," and the Updated Final Safety
Analysis Report (UFSAR).
b. 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 samplers.
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 REMODCM.
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 *
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(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 6.8.1
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 valid.
c. 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 UFSAR.
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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R1.2 Meteorofoaical Monitorina Prooram (MMP)
a. 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
b. 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 ;
l made repairs or replacements as needed. '
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
'
efficiency to repair or replace instruments. 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
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and the results were generally within acceptance criteria established in the procedures.
c. 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 recommendations.
R2 Status of Radiological Protection and Chemistry Facilities and Equipment
R2.1 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 13,1995.
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.
l
The letter stated:
i
"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.
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 conditions.
In addition, a secondary cause is an apparent absence of ownership for the
radwaste systems from an operating, engineering, and maintenance perspective.
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 state.
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 goals.
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 respects.
R5 Staff Training and Qualification in Radiological Protection and Chemistry
a. 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 personnel.
b. 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 1.
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 applicable.
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 programs. I
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c. Conclusions
l
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 area.
R6 Radiological Protection and Chemistry Organization and Administration
a. 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
a. 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 6.9
of the TS.
b. 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 same.
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 1979.
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 area.
The inspector detstmined that the changes continued to meet the intent of
the environmental sampling program.
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 trends.
c. 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 REMODCM.
R7 Quality Assurance in RP&C Activities
R7.1 Quality Assurance Audit Proaram
a. 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 TS. !
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- ' b. Observations and Findinas
i
The inspector reviewed the following Quality Assurance Audit Report as part ;
of the evaluation of the implementation of the TS audit requirements.
'
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Quality Assessment Services (QAS) Audit Report, Audit No. ;
A25106/A24053, Radiological Effluent Monitoring and Offsite Dose i
! Calculation Manuals (REMODCM)-1995. i
,
'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 site. ;
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 area. 1
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 TS. i
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c. 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
requirements.
I R7.2 Quality Assurance and Quality Control Proarams
a. 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
REMP.
b. 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 :
{
good insight for improvement where needed. An interlaboratory comparison i
'
program was continued using Analytics, Inc. since EPA discontinued the
program, with the exception of drinking water,in January 1,1995. The .
,
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
'
analyses were performed. The inspector reviewed the analytical results and
.
noted the results were within the licensee's established acceptance criteria. 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
<
compared them the known value using their own quality control acceptance i
,
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
3
- 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 results.
1
The inspector also reviewed the " Semi-Annual Quality Assurance Status !
Reports" for 1995 and the first half 1996, which summarized the analytical
'
results from the blind duplicate (split) samples and interlaboratory programs. !
' ' 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 resolved.
I
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c. Conclusions
'
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 audits.
b. 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 plant.
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 process.
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 Coordinator. 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 Coordinator.
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 effort.
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 ,
'
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 information.
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 !
!
programs reviewed by the unit radiation protection staff during visits to other nuclear
! facilities.
l
- 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 support.
l
c. 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 unit.
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.
1 t) nit 1
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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 unit.
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, however.
P2 Conduct of Emergency Preparedness Activities
P2.1 (Closed) Insoector Followuo item 50-245, 336,423/95-36-01: Emeraency -
Preoaredness Annual Exercise
a. Scope
This inspection involved the observation of the Millstone Unit 2 partial participation
exercise that occurred on November 21,1996. 1
i
b. 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 generator.
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 good.
- 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 minutes.
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 monitorirg.
- 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 separately.
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
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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 concern.
c. 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 report.
P8 Miscellaneous Emergency Preparedness issues
P8.1 Millstone Call-in Drill I
i
a. 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
b. 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 operations.
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 responders.
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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 security.
. 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 system.
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 limit.
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 staff.
-c. 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
4
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 met.
S1 Conduct of Security and Safeguards Activities
7
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 security.
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 ':HC.
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 station.
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The licensee promptly coracluded that no security breach had occurred.
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 taken.
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 1. i
.
S8 Miscellaneous Security and Safeguards issues
S8.1 [ Closed) URI 50-245/96-06-16: Unauthorized Entrv Into the Protected Area
a. 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 50-245/96-06.
b. 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 shift.
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 responded.
c. 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
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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 presented.
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
parameters.
While performing the inspections which are discussed in this report the inspectors
reviewed the applicable portions of the UFSAR that related to the areas inspected. The
following inconsistencies were noted between the wording of the UFSAR and the plant !
. practices, procedures and/or parameters observed by the inspectors, as documented in 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.E8.2. l
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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 FSAR.
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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 functions.
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
29,1996.
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 1.
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INSPECTION PROCEDURES USED ,
IP 37551: Onsite Engineering
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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
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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
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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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ITEMS OPENED, CLOSED, AND DISCUSSED
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eel 245/96-09-01 U1.01.2 Timeliness of Reportability Assessment
eel 245/96-09-02 U1.06.1 Qualifications of Unit Director
URI 245/96-09-03 U1.06.2 Organizational Changes
VIO 245/96-09-04 U1.06.2 Modified TS Responsibilities
eel 245/96-09-05 U1.07.1 QA Report Corrective Action Not imp.
eel 245/96-09-06 U 1.M 8.1 RCPB Piping IGSCC/ Structural Integ.
eel 245/96-09-07 U1.E1.1 EDG Air Start Valves '
l eel 245/96-09-08 U1.E3.1 GL 89-13 Inaccurate Corresp.
l URI 336/96-09-09 U2.03.1 EP Exercise Operator Override SIAS
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NCV U2.M1.1 TS Verbatim Compliance
eel 336/9t -09-10 U2.E2.1 EDG Bearing Failures
URI 245/423/
96-09-11 U 3.M2.1 Arcor Epoxy Lining Failures
l URI 423/96-09-12 U3.M 3.1 Ommission of SSCP From Scope
URI 423/96-09-13 U 3.M 3.1 Systems Omitted From Maintenance Rule without Basis
{ IFl 423/96-09-14 U3.M3.1 Maintenance Rule Scoping
IFl 423/96-09-15 U3.M3.2 HVAC Heat Load Modelling
eel 423/96-09-16 U3.E2.1 Air SOV Over Pressurization
IFl 423/96-09-17 U3.E2.2 EDG Exhaust Stack
NCV U3.E8.2 Ni Channels Not Tested
NCV U3.E8.3 EDG Control Panel Latches
VIO 245/336/423
96-09-18 R1.R1.1 Failure to Calibrate TLD Survey Meter
eel 245/96-09-19 PS.R2.1 Radwaste inaccurate Correspondence
VIO 245/96-09 20 PS.S 8.1 Unauthorized Entry into PA
Closed Section t
245/96-06-16 PS.S8.1 '
245/96-06-03 U 1.M 8.1
336/96-05-08 U2.M 8.1
423/96-08-19 U3.E2.1
245/336/423
95-36-01 PS.P2.1
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423/95-44-06 U3.E8.1
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The followina LERs were also closed durina this inspection:
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96-03 .
96-04
96-05 & 96-05-01 l
l 96-18
96-22
, 96-25
l '96-30 , 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 P. 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
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
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NGP Nuclear Guidance Procedure
NNECO Northeast Nuclear Energy Company
NPRDS Nuclear Plant Reliability Data System
NRC Nuclear Regulatory Commission
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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
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
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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
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
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SFP spent fuel pool [
SlAS safety injection actuation system l
SORC site operations review committee i
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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
UFSAR updated final safety analysis report .
l UIR unresolved indication report ;
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l URis unresolved items
USQ unreviewed safety question ;
i Vdc volts, direct-current i
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VIO violation !
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DECEMBER 5,1996
PRE-DECISIONAL ENFORCEMENT CONFERENCE
MILLSTONE SIMULATOR
l LIST OF ATTENDEES
NB.Q 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
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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
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