IR 05000245/1997002: Difference between revisions

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{{Adams
{{Adams
| number = ML20141E341
| number = ML20217Q000
| issue date = 06/24/1997
| issue date = 08/14/1997
| title = Insp Repts 50-245/97-02,50-336/97-02 & 50-423/97-02 on 970311-0519.Violations Noted.Major Areas Inspected: Operations,Maintenance,Engineering & Plant Support
| title = Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-245/97-02, 50-336/97-02 & 50-423/97-02 Issued on 970624.Actions Will Be Examined During Future Insp
| author name =  
| author name = Durr J
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| addressee name =  
| addressee name = Carns N
| addressee affiliation =  
| addressee affiliation = NORTHEAST NUCLEAR ENERGY CO.
| docket = 05000245, 05000336, 05000423
| docket = 05000245, 05000336, 05000423
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-245-97-02, 50-245-97-2, 50-336-97-02, 50-336-97-2, 50-423-97-02, 50-423-97-2, NUDOCS 9707010034
| document report number = 50-245-97-02, 50-245-97-2, 50-336-97-02, 50-336-97-2, 50-423-97-02, 50-423-97-2, NUDOCS 9708290104
| package number = ML20141E286
| title reference date = 07-25-1997
| document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| document type = CORRESPONDENCE-LETTERS, OUTGOING CORRESPONDENCE
| page count = 102
| page count = 3
}}
}}


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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION SPECIAL PROJECTS OFFICE i
Docket Nos.:
50-245 50-336 50-423 l-Report Nos.:
97-02 97-02 97-02 License Nos.:
DPR-21 DPR-65 NPF-49 Licensee:
Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06386 Facility:
Millstone Nuclear Power Station, Units 1,2, and 3
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Inspection at:
Waterford, CT Dates:
March 11,1997 - May 19,1997 Inspectors:
T. A. Easlick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 A. L. Burritt, Resident inspector, Unit 1 R. J. Arrighi, Resident inspector, Unit 3 L. L. Scholl, Reactor Engineer, SPO N. J. Blumberg, Project Engineer, SPO R. J. Urban, Project Engineer, SPO D. T. Moy, Reactor Engineer, Region 1 J. E. Carrasco, Reactor Engineer, Region I D. A. Dempsey, Reactor Engineer, Region i Approved by:
Jacque P. Durr, Chief Inspections Special Projects Office Nuclear Reactor Regulation l
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9707010034 970624 PDR ADOCK 05000245 G
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I SUMMARY
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Millstone Nuclear Power Station Combined Inspection 245/97-02:336/97-02;423/97-02 l
Operations At Unit 1, operator response to the ESF actuation was excellent. Operator control
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and monitoring of plant parameters following the event and throughout the systems restoration were appropriate. Shift supervision maintained good command and
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control throughout the event. The assessments and verifications performed by the shift technical advisor were outstanding. (U1.01.2)
The reportability determination (RD) performed at Unit 1,in response to a condition
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report (CR) concerning a design basis for the EDG with respect to outside air temperature, did not contain a sufficient technical basis for the conclusion that the CR was not reportable. This is a particular concern since the RD had received three levels of review. (U1.01.3)
l Overall, the implementation of procedure RP-4, " Corrective Action Program,"
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revision 4 has not resulted in significant improvements in the corrective action process at Unit 1. The revision of the CR process was poorly implemented in that specific guidelines were not put in place to ensure the initiation and appropriate processing of CRs for conditions adverse to quality. However, a number of management initiatives were implemented during this period and have resulted in improvements, such as corrective action plan quality, in general, improvement was noted throughout the period on many of the weaknesses discussed in this report.
 
However, CR trending reports were not being issued as required by procedure and is an apparent violation of NRC requirements. The interface between RP-4 and other lower tier deficiency reporting processes and the proper implementation of those processes are considered unresolved pending the licensee's evaluation and implementation of corrective actions as appropriate. (U1.01.4)
Condition reports are not being initiated consistent with the program requirement
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described in procedure RP-4 at Unit 1. Based on discussions with the Unit 1 staff, and also upon the number and significance of some of the examples either not reported, reported after NRC prompting, or delayed without alternative reasons, there appears to be some apprehension to initiate CRs. Although, corrective action process implementation weaknesses have been identified with procedure controls, training and inconsistent expectations, there also appears to be some reluctance for personnel to document problems. Several deficiencies were also noted in the initial operability and reportability screening for a number of the CRs reviewed. (U1.01.5)
The process for training and/or familiarization prior to the implementation of Nuclear
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Group Procedure 2.25, Revision 10, Reportability Determinations, at Unit 1,is not clearly defined, particularly in the area of familiarization training. Th!s issue is unresolved pending completion of additional NRC and licensee revir.w. (U1.03.1)
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==SUBJECT:==
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COMBINED INSPECTION REPORT NOS. 50 245/97-02,50-336/97 02, AND 50-423/97-02 (REPLY)
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Unit 1 har not implemented appropriate controls for the replacement of main control
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panel indicating lamps that are required to be OA category 1. The bulbs in a number of these applications are typically replNed with non-QA and uncontrolled bulbs. The use of non-OA bulbs in a QA aps.;ication is unresolved pending the-licensee's review of the issue and implementation of appropriate corrective actions.


(U 1.08.1 )
==Dear Mr. Carns:==
The Unit 2 backlog of 828 condition reports (CRs) that are greater than 120 days
This letter refers to your July 25,1997 correspondence, in response to our June 24,1997 letter.
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old indicates that timeliness for completing corrective actions continues to be a concern. Although the 120-day-old CR backlog has increased from 798 since the last inspection period, the total number (all ages) of open CRs has declined slightly from 1335 CRs in January to 1215 CRs in April 1997, which is a positive trend.


(Section U2.01.2)
Thank you for informing us of the corrective and preventive actions documented in your letter. These actions will be examined during a future inspection of your licensed program.
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At Unit 2, a comparison of the inspection results of 16 open items [ Licensee Event
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Reports (LERs), Escalated Enforcement item (EEI), Violations, and Unresolved items (URis)) reviewed in NRC Inspection Report (IR) 50-336/96-08 and 15 open items reviewed in this inspection report indicates that the licensee had made some progress regarding the quality of corrective actions. In this report, the corrective actions for 12 of 15 open items were acceptable while only 4 of 16 were acceptable in IR 50-336/96-08. In this report, a violation was issued for 1 of 15 open items while 7 Eels and 2 violations were created associated with the 16 open items discusced in IR 50-336/96-08. (Section U2.01.2)
The NRC followup of Unit 3 operational controls related to the Safety Grade Cold
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Shutdown (SGCS) design features of the unit identified an event that was determined to be reportable in accordance with 10 CFR 50.73. A technical specification revision is being developed to address some of the concerns regarding SGCS equipment controls. However, the need for comprehensive action to address the NRC unresolved item on this topic is further highlighted by the fact that the identified event would not have been reported without NRC questioning in this area.
 
(U3.01.2)
Several Unit 3 LERs discuss conditions prohibited by technical specifications (TS).
* Individually, the issues were of low safety significance and are being treated as Non-Cited Violations. However, the closure of the LERsdoes not address the generic concern for TS compliance. A review of LERs issued since April 1996 revealed that there have been a number of LERs that have dealt with TS compliance problems relating to questionable interpretations. This area is of current interest for further NRC review and is included as an NRC followup activity; documented as Significant items List (SIL) item 70. (U3.08.1)
Maintenance At Unit 1, the licensee has successfully implemented the FIN team concept, a multi-
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discipline, independent, and self-sufficient work team. This t6am has made a positive contribution to the work effort, completing over 1000 AWOs since the team was implemented ir. November 1996. A significant number of process v
 
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assessments, worker observations, and a self-assessment on the team have resulted in improvements in the process. The concept of cross-training within the disciplines on the team was considered a strength. (U1.M1.1)
At Unit 2, the operator's decision to unisolate the "B" emergency diesel generator
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(EDG) starting air prior to filling and venting the lube oil system was considered to be a significant weakness, particularly in light of the fact that the "B" EDG was
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extensively damaged last year as a result of insufficient lubrication during routine
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engine fast starts. The performance of the maintenance technician was excellent in


1 identifying this condition. The associated root cause analysis was of high quality.
Your cooperation with us is appreciated.


(Section U2.M1.1)
Sincerely, ORIGINAL SIGNED BY:
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Jacque P. Durr Chief, inspections Special Projects Office Office of Nuclear Reactor Regulation Docket Nos. 50 245;50-336:50-423 200087
Over the last six months, NRC inspection reports have discussed 17 licensee event
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reports (LERs) at Unit 2 involving inadequate surveillance procedures. For five of the earlier LERs, the NRC either identified the issue or NRC intervention was
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necessary to achieve satisfactory corrective action. In the response to Violation
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336/96-08-07, which addressed inadequate containment integrity valve lineups, the licensee committed to review all TS surveillance procedures for adequacyc Several
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more recent examples of inadequate surveillances were identified by the licensee as i
IllE ElliJil,E RJM 9708290104 970814 PDR ADOCK 05000245 O
a result of this commitment. Other examples are the result of reviews conducted as part of their 10 CFR 50.54(f) effort and the reviews for Generic Letter 96-01,
PDR
" Testing of Safety-Related Logic Circuits." The more recent examples were generally licensee-identified, however, these appear to be repetitive violations and are being considered collectively as an apparent violation. The NRC Significant i
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items List, item 8, lists surveillance procedure adequacy as an issue that the licensee must satisfactorily address prior to restart. (Section U2.M3.1)
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At Unit 2, a previous violation regarding an inadequate containment integrity valve
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lineup could not be closed because the revised valve lineup still did not provide sufficient guidance to operators. The NRC found that for valves in systems that j'
must be in service (such as the shutdown cooling system in Mode 4,) the valve position specified was Open/ Closed or Locked Closed /Open without any notes or instructions to explain when or under what conditions, the open position would be acceptable..The licensee is revising the associated technical specification amendment to address the concern. (Section U2.M8.3)
At Unit 2, the location specified in the shiftly surveillance for measuring the ultimate
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heat sink temperature was not in strict compliance with technical specifications.


This licensee-identified concern was characterized as a non-cited violation. (Section U2.M8.6)
A review of Unit 3 maintenance activities rever/3d that iho tagging boundary and
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retest requirements for observed work activitics were adequate. (U 3.M 1.1 )
The Unit 3 licensee's handling of design change documents related to one as-built
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pipe whip assembly inspected by the NRC represents a concern. Additionally, the
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licensee's handling of ASME Code references and Code Case usage as design input l
information has resulted in some condition reports requiring followup. These issues vi
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I information has resulted in some condition reports requiring followup. These issues merit further attention to ensure that they are not ref!ective of programmatic
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problems with the licensee's procurement, modification and configuration management processes. (U3.tvl2.1 and M7.1)
Engineering For Unit 1, the licensee identified long-standing examples of noncompliance with
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the primary containment leak rate test provisions of 10 CFR 50, Appendix J.
l System configurations and test procedure deficiencies resulted in the inability to demonstrate primary containment integrity. The magnitude and variety of problems indicated a programmatic breakdown of the Appendix J program. Failure to
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implement an effective containment leak rate test program properly is an apparent violation of 10 CFR 50, Appendix J. (U1.E1.1)
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For Unit 1, several examples were found of missed opportunities to havc identified
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and corrected containment leak rate test deficiencies prior to the Appendix J program review conducted in 1996. This is an apparent violation of the corrective
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action requirements of 10 CFR 50, Appendix B, Coterion XVI. (U1.E1.1)
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For Unit 1, failure to maintain drawings consistent with the plant configuration and
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to apply administrative controls to valves 1-FW-107 A and B commensurate with l
those applied to similar manual containment isolation valves is a violation of NRC design control requirements. (U1.E1.2)
In the context of low pressure coolant injection system heat exchanger capability
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for Unit 1,9pparent violations of NRC requirements were identified pertaining to performance of safety evaluations per 10 CFR 50.59 and extended operation beyond the plant licensing basis, operability of the containment cooling system, and corrective action for heat exchanger tube fouling. (U1.E1.3)
Failure to maintain the Unit 1 Updated Final Safety Analysis Report consistent with
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the current plant licensing basis was an apparent violation of 10 CFR 50.71.
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(U1.E1.3)
The licensee planned to perform a test of the Unit 1 core spray system in the
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recirculation mode, using normal surveillance procedures. Since a 10 CFR 50.59 review / screening had not been performed in preparation for this test, the intervention of the inspector prevented a potential violation of NRC requirements.
The NRC is concerned that a vulnerability exists, which would have allowed the performance of an unreviewed test to occur. This item remains unresolved pending further licensee evaluation and NRC review. (U1.E1.4)
At Unit 1, the licensee's corrective actions for the replacement of CU-29, and
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performance of the required localleak rate testing was found to be acceptable. The failure of the as-found localleak rate test and evidence of the longstanding leakage of CU-29 is contrary to Technical Specification 4.7.A.3.e.(1)(a), which requires a combine leakage rate of less than 0.60 La (300.3 scfh) for all penetrations and vii r
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requirements. Additionally, the licensee failed to consider all recent discrepant conditions, related to containment integrity and evaluate the aggregate impact. The safety implication appears more significant than was discussed in LER 96-? 2.
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(U 1.E8.2)
At Unit 2, bulges in several containment liner plates that have existad since original
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construction were found to have been adequately evaluated by the licensee.
(Section U2.E2.1)
A Unit 2 unresolved item was reviewed concerning an enclosure building ventilation
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damper with a single failure vulnerability that could result in exceeding 10 CFR 100 limits for offsite doses. The NRC decision to not backfit the licensee to address this vulnerability was based heavily on the operator compensatory action described in LER 50-336/94-40-02 involving securing the main exhaust fans in response to the Unit 2 stack radiation monitor alarm. However, the inspector found that the
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licensee's corrective actions were inadequate in that the alarm response procedure fai!ed to ensure the main exhaust fans were secured. This was characterized as a violation. (Section U2.E8.2)
The inspector reviewed two LERs which discussed conditions where installed
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equipment or actual plant configeration differed from the Final Safety Analysis Report descriptions. These errors did not directly impact the safe operation of Unit 3. The specified design concerns have either been corrected, or are scheduled to be fixed prior to plant startup. The effectiveness of the design control process at Millstone Station is under current NRC review and is included as an Independent Corrective Action Verification Program followup activity that is documented as Significant items List (SIL) item 79. (U3.E1.1)
Adjustments made to the inservice inspection (ISI) schedule due to the extended
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shutdown were reviewed. The planned ISI schedule was prepared in accordance with an extension allowed by section IWA-2430 of the ASME Code, Section XI. As a sample inspection for ASME Class 1, Class 2, and Class 3 components, the inspector reviewed the Reactor Pressure Vessel (RPV) ISI, welds in the chemical volume and control system, and component conditions in the component cooiing and service water systems. The inspector noted that the results of the most recent RPV ISI will be submitted to NRR, along with an alternative for an augmented examination of the subject welds. The Class 2 piping ISI observations made by NRR are being addressed by the licensee in accordance with the ASME Code. With the exception of some extemal corrosion of the Class 3 components, which was appropriately addressed by the licensee, no deficiencies were identified. (U3.E1.2)
The inspector discussed with the licensee whether loss of an emergency diesel
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generator vice a loss of a single main steam pressure relieving bypass valve was the most limiting failure for the Unit 3 steam generator tube rupture margin to overfill analysis. Continued NRC review of this issue is planned as an inspector followup item. (U3 E2.1)
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Plant Support
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The licensee has demonstrated a significant increase in management attention
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towards the liquid radwaste systems at Unit 1. However, management oversight for liquid radwaste systems at Unit 3 still warrants attention.
 
A repeat violation was issued for radiation workers failure to wear dosimetry
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pursuant to written radiation protection program instructions. The violation is discussed in detailin the Plant Support section of this report. (IV.R1.1)
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e Report Details Summarv of Plant Status Unit 1 remained in an extended outage for the duration of the inspection period. The licensee continues to implement configuration management program activities, engineering reviews, and docketed correspondence assessments to verify compliance with the established design and licensing basis of the unit. The successful completion of these activities is required by NRC order prior to restart of the unit. During this period, the licensee announced that Unit 3 was designated as the lead unit and would be the first unit ready for external review under the provisions of the independent Corrective Action Verification Program (ICAVP). In addition, the Units 1 and 2 recovery officers will assist Unit 3 in its recovery process, and will assume additional responsibilities in the area of physical plant readiness and regulatory readiness respectively. While there will be a reduction of restart activities at Unit 1, through the end of this year, configuration management program activities will continue.
 
U1.1 Operations U101 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. During this period the inspectors noted that an operating crew identified and stopped planned work that was not properly reviewed for shutdown risk implications.
 
Specifically, while the crew was reviewing work activities for their upcoming shift, they identified that the 12F transformer replacement plan had not fully considered the potential single failure vulnerability created during the work activities. This demonstrates an appropriate questioning attitude and maintaining positive control and oversight of ongoing work activities by the operations staff.
 
01.2 Operator Response to an inadvertent ESF Actuat'on a.
 
Inspection Scone (71707)
On April 9,1997, during l&C activities, a perturbation occurred on an ESF instrument rack.
 
This anomaly caused an initiation of the reactor low ad low-low water level emergency safeguard feature (ESF) logic and resulted in a loss of emergency service water, reactor building ventilation, reactor water cleanup, along with a start of the gas turbine emergency generator. The inspector observed the operator response to this event.
 
b.
 
Observations and Findinas The operators verified that the plant responded as expected including a subsequent independent verification. The fuel pool and reactor building closed cooling water systems were closely monitored and temperatures recorded for trending. Procedures were used as appropriate. The operators at the controls effectively used the control room annunciators to reconstruct and diagnose the event.
 
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The shift manager had non essential personnel leave the control room area during the event. The senior control operator appropriately established the priorities for system
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restorations. For example, the emergency service water was returned to service in a
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controlled manner within 16 minutes of the event initiation, allowing only a 1 degree Fahrenheit increase in spent fuel pool temperature. The shift manager also stopped all I&C work activities pending an investigation into the cause of the event. An off duty shift manager helped coordinate additional resources such as engineering support to confirm the cause of the event, j
A shift technical advisor (STA)in the cuntrol room at the time of the event assisted the operators with the monitoring of the plant response and key parameters. The STA anticipated what assessments were needed, and typically completed the task before his assistance was requested. In addition, the STA backed up the initial operator assessments such as expected plant response and a verification of isolation valve status.
 
l Throughout the event the telephones at the operators desk were continuously ringing.
 
Although most of the essential communications were performed via radio in some cases the phone system was used to provide equipment status to the control room. Many of the calls received by the control room were non-essential and had the potential to distract the i
operators. The potential for operators to be distracted by non-essential calls was discussed with operations management. The operations manager stated that the issue was already being reviewed.
 
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Conclusion Operator response to the ESF actuation was excellent. Operator control and monitoring of plant parameters following the event and throughout the systems restoration was appropriate. Shift supervision maintained good command and control throughout the event. The assessments and verifications performed by the STA were outstanding.
 
However, throughout the event the phone system was a potential distraction for the operators.
 
01.3 Reoortability Determination Review a.
 
inspection Scope (71707)
The inspector reviewed the reportability determination (RD) performed in response to condition report (CR) M1-97-0954, which questioned if the emergency diesel generator (EDG) was historically operable with outside air temperature below zero degrees Fahrenheit, b.
 
Observation and Findinas The reportability section stated that "this CR has been screened for reportability against the outside design basis criteria, and found to be not reportable." The RD referenced the Unit 1 and Unit 3 FSAR sections which discussed the design basis outside air temparature for the plant. Based on that discussion, the RD concluded that "the EDG design meets the design basis outside air temperature for Millstone." This RD did not answer the obvious
 
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1 question of whether or not the EDG was outside its design basis if the outside air temperature dropped below zero degrees Fahrenheit. This issue was discussed with operations and engineering management, and a revised RD was completed on May 9, 1997. While the new RD arrived at the same conclusion, that the issue was not
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l reportable, it did provide the requisite technical basis to support that conclusion, including
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calculations that indicated that the air intake piping contained sufficient prewarmed air to start the dieselindependent of outside air temperature.
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Conclusion.
The reportability determination performed to aodcass the EDG's capability to start at temperatures less than zero degrees Fahrenheit, did not contain a sufficient technical basis
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for the conclusion that the CR was not reportable. This is a particular concern since the RD had received three levels of review with signoffs from a peer / supervisor, a licensing j
manager, and a unit director or designee. In this case the designee was a shift manager.
01.4 lmolementation of the Condition Report Process (SIL 17 UPDATE)
a.
Insoection Scope On February 25,1997, a revision to RP-4, " Corrective Action Program," was implemented.
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The purpose of the change was to simplify the corrective actions process and allow the incorporation of improvement items in the process instead of limiting the process to adverse conditions only. The inspectors rev!ewed various aspects of the implementation to assess the licensee's corrective action process, b.
Observations and Findinas Based on discussions with the licensee, the key improvements of the revis!on were to restructure the CR levels for simplification and to provide the inclusion of enhancement issues into the corrective action process. The revision also provided formal expectations on reportability and corrective action timeliness along with the requirement for measures of effectiveness for the most significant issues. In addition, the procedure requires more involvement by the corrective action group in assessing the evaluations performed to resolve CRs and the associated corrective actions. The licensee also stated that the procedure change requires more management oversight of the process.
Trainina Prior to implementation of the revision to RP-4, a formal training presentation was provided on the changes to the directors, managers, and selected supervisors. The directors and managers in turn provided a familiarization overview of the changes to the rest of the unit staff, during departmental meetings and via a familiarization handout. A review of the attendance of the formal training performed identified that half of the shift managers and ceveral senior control operators were not trained on the RP-4 revisions. Further, none of the maintenance or instrument and control supervisors attended the formal training, instead they attended a familiarization course. According to the corrective action manager, most of the changes to RP-4 did not effect the portions of the process that supervisors are
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Mr.- N. :
2-cc:-
M. H. Brothers, Vice President - Millstone, Unit 3 J. McElwain, Unit 1 Recov< ry Officer
- M. Bowling, Jr., Unit 2 Recovery Officer D. M. Goebel, Vice President, Nuclear Oversight J. K. Thayer, Recovery Officer, Nuclear Engineenng and Support P. D. Hinnenkamp, Director, Unit Operations =
F. C. Rothen, Vice President, Work Services J. Stankiewicz, Training Recovery Manager R. Johannes, Director - Nuclear Training
- cc w/cy of Licensee Response Letter:
_ L. M. Cuoco, Esquire J. R. Egan, Esquire V. Juliano, Waterford Library.
' J. Buckingham, Department of Public Utility Control S. B. Comley, We The People State of Connecticut SLO Designee D. Katz, Citizens Awareness Network (CAN)
R. Bassilakis, CAN J. M. Block, Attorney, CAN -
S. P, Luxton, Citizens Regulatory Commission (CRC)
Representative T. Concannon E. Woollacott, Co Chairman, NEAC


typically involved with, so mandatory training was not necessary. However, the inspector determined that one of the most significant changes had to do with the CR initiation threshold and the associated CR levels. In addition, RP-4 does not contain clear guidelines or criteria as to when a CR should be initiated nor were the expectations clearly provided via training based on a review of the associated records. The inspector also noted that RP-4 made a special note of the importance of the supervisor in the corrective action process.
Specifically, the supervisor determines the appropriate reporting method and serves as a
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quality check to determine if the condition meets the CR threshold. During this inspection
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period a lack of familiarity with CR severity levels was also noted at the moming meeting.
* Following a discussion with the inspector, the licensee agreed to revaluate the adequacy of
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the training provided following the completion of a planned self assessment. Additional l
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training would be prm6ied as appropriate.
 
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l The training provided for the revision of RP-4 was not commensurate with the limited criteria that describe the threshold for CR initiation. In addition, the failure to provide q
detailed training to all supervisors resulted in the loss of a barrier in ensuring the prompt
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and appropriate initiation and processing of CRs.
 
Timeliness A review was performed to determine if adverse or discrepant conditions, identified via a I
CR, were being promptly addressed for operability and reportability. RP-4 requires that the
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supervisor and operational reviews occur within 24 hours of CR initiation. A review of the intervals between event identification and initial assessment of operability and reportabilit'/
determined that based on the method in which the CR dates are recorded and tracked, there is no way to assess the processing of CR beyond reviewing each CR individually.
 
Based on daily observations of the CR process, numerous CRs required several days to a
. week from the initiation through the operational review by the shift manager or designee.
 
The licensee initiated a CR to address the processing delays and the lacia of event dates and times. In addition, the licensee plans to revise the convention for input of dates into the computer system such that evaluations can be performed of CR operational redew timeliness.
 
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The revision to RP-4 included guidelines for the development of the corrective action plans within 30 days of the assignment to a responsible individual. A review of CR initisted following the implementation of the RP-4 revision, identified that approximately 80% of the 63 CRs (past the initial 30 day point) did not have corrective action plans developed. The licensee initiated a CR to address the high percentage of CRs not meeting the 30 day guideline.
 
Delays in identifying and processing CRs has resulted in delays in assessing operability and reportability of numerous issues; however, no consequential issues were identified. A high percentage of CRs generated during the inspection period did not result in the developrnent of corrective action plans consistent with the procedural expectations.
 
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Sionificanco Lovej J
A review rformed to determine if CRs were being assessed at the appropriate level and there.
 
xoiving the proper level of management attention. A sample of 19 of a total of 261 CRs of the more significant level 2 and 3 CRs were selected for specific evaluation.
 
The review identified that 7 of the 19 CRs were incorrectly assessed at too low of a level.
 
The licensee subsequently upgraded the CR levels as appropriate. An additional 2 of the
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19 CRs were dispositioned at a level appropriate to the reported condition; however, the licensee failed to perform a followup trend analysis to identify a broader issue that would have increased its sign!ficance to the level 1 threshold. Aside from receiving additional management attention, adverse conditions assessed to be level 1 CRs require the implementation of measures to ensure corrective action effectiveness and are forwarded to the Nuclear Safety Assessment Board for review.
 
The review of CR level dispositions also identified that a number of adverse conditions were dispositioned at a level higher than warranted by the reported condition. For example, security issues involving improper control of safeguards information, keys left in unattended vehiclec ;aside the protected area, and an improperly controlled security key card were determinad to be level 1 issues, but did not appear to meet the related threshold. Based on discussions with the licensee's corrective action staff, these adverse conditions had been assessed as leval 1 as a result of trends; however, the licensee had not performed the trend analysis to support the assumption that a broader issue existed.
 
A review of level 1 CR issues was performed to determine if root cause evaluations were l
being performed as appropriate. A sample of 19 level 1 CRs was reviewed and found that
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root cause evaluations were performed for all but 5 of these CRs. For the 5 cases in which a root etuse evaluation was not performed, the licensee had an adequate bases for not
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performing the more detailed evaluation.
 
A general lack of familiarity or understanding of CR severity level classification was observed. A number of CRs sampled were inappropriately assessed at too low of a level, resul ting in the potential for inadequate msnagement attention and oversight. In addition, leve! 1 issues that are incorrectly classified would not require measures to assess effectiveness of the corrective actions. Problems were also noted with the licensee's staffs understanding of how the initial operability and reportability screening should be addressed for equipment that is out of service at the time of discovery.
 
Administrative Controls A review of the CR backlog was performed and identified an increasing trend with 1943 open CRs at the beginning of the inspection period and 2193 open near the end of the period, with 558 new CRs generated. Notwithstanding the high number 9f CRs generated during the period, CRs were not being consistently initiated in accordance with program requirements as discussed in Section 01.5. Two initiatives were implemented to f acilitate the reduction of the CR corrective action plan backlog. The first was "CR day," which was a unit wide work focus for two, one-day sessions to develop corrective action plans for open CRs. This initiative resulted in an approximately 25% reduction in the backlog of CRs awaiting evoluation and development of corrective action plans. The second initiative was


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the development of a "CR team" which screens the previous days CRs, gathers additional information when necessary, and makes an initial assessment. The CRs are then presented to the management tearn with appropriate recommendations, in many cases, the CRs are subsequently assigned to the CR team for development of the corrective action plan within a couple of days. Although, these initiatives have caused a reduction in the backlog of needed CR evaluations, and may improve the timeliness of development of corrective action plans in the future, the CRs will remain open until all corrective actions are implemented. An accompanying increase in the open corrective actions requiring implementation, indicates that although the open CR backlog is increasing, a significant percentage of those CRs have moved further in the process and are closer to implementation.
Region I Docket Room (with ggpy of concurrences)
 
Nuclear Safety Information Center (NSIC)
Although a number of initiatives such as CR day and the establishment of a CR team have been implemented during this inspection period, these efforts have not turned the
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FILE CENTER, NRR (with Orioinal concurrences)
increasing trend in the open CR corrective action backlog.
NRC Resident inspector B. Jones, PIMS/ DISP M. Kalamon,- RPO, RI W. Lanning, Deputy Director of Inspections, SPO, RI D. Screnci, PAO W. Travers, Director, SPO, NRR
 
- J. Andersen, PM, SPO, NSR M. Callahan, OCA R. Correia, NRR W. Dean, OEDO l
Curing a review of specific CRs, a number of administrative controls weaknesses were noted. Specifically, RP-4 does not require the documentation of the bases for the l
- S. Dembek, PM, SPO, NRR G. Imbro, Deputy Director of ICAVP Oversight, SPO, NRR
reportability assessment for section 2 or section 3 of form RP4-1, if no is checked. The lack of specific details led to a significant amount of research, by the licensee, in order to establish the bases for the assessments, in addition, some of the shift managers were addressing the questions in sections 2 and 3 of the CR form differently, depending on whether or not the system or component was in an operable status at the time of discovery. However, RP-4 does not provide guidance to support different approaches depending on the equipment operability status. In addition, RP-4 does not describe how and when personnel questionnaires should be used and controlled. Personnel questionnaires are used for future evaluations and to record the conditions, circumstances and actions taken during an event, Trendina In October 1996, the sitewide corrective actions group was disbanded, as Northeast Utilities moved to a unitized approach for implementation of most processes. Shortly after that time, the licensee stopped performing trend analysis as required by RP-4 revision 2, in effect at that time. The procedure required analysis of data to identify trends. Specifically, the procedure states on a monthly basis, issue a report covering apparent adverse and positive trends and other topics as appropriate. The QA topical report also discusses the use of trend analysis reports as a means for meeting 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action." The last trend report performed was for the month of October 1996. CR M1-97-0258, initiated by the nuclear oversight organization, identified this issue
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in February 1997. The CR corrective actions discussed a revisic,n of the trend requirement to a quarterly periodicity, the development of guidelines for trending and to perform interim trend analysis until the first quarterly report is issued. However, at the end of the inspection period the licensee had not completed the interim trending. This is an apparent l
violation of the RP-4 procedure and is viewed as another example of the previously identified programmatic breakdown of the licensee's corrective action process discussed in t
NRC report 96-04. (eel 245/97-02-01)
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The current revision of RP-4 requires quarterly trending of CRs; however, no program guidelines or expectations have been established to address how and what areas should be trended at this periodicity. Additionally, no guidelines or protocols have been established for as needed trending based on repeat occurrences observed during the management review of CRs. However, as a result of management initiatives, a number of trends have been identified. For example, a clearance and tagging problem, personnel performance issues related to security, radiation and worker practices, automated work order compliance, and use of personnel protective equipment, have been identified.
 
Other Deficiency Processes Procedure RP-4, " Corrective Action Program," is one of the processes listed in the topical report to address the corrective action requirements. RP-4 lists design deficiencies among other things that warrant a condition report (CR). As a result of the extensive design reviews, the licensee has established another process to address potential design deficiencies, namely the unresolved item report (UIR). The process is described in Project Instruction (PI) 14 but is not a process described by the QA topical report as a process used for compliance with Appendix B Criterion 16.
 
CR M1-97-0824, identified reactor protection instrumentation not in conformance with design requirements. The licensee planned to close this CR with no action and reference the associated UlR for corrective action. The licensee immediately suspended the practice of closing CRs to UIRs in part, based on discussions with the inspector. The licensee staff stated that a review of the QA Topical Report and RP-4 had been performed and found the a
use of the UIR process as an extension to the CR progress acceptable. However, a
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subsequent review determlned that the practice was unacceptable. The licensee's staff did not elaborate on bases for the change in assessment.
 
The nuclear oversight organization performed surveillance MP1-P-97-018 to assess trouble reports and corrective maintenance automated work orders for adequacy of condition reporting on plant equipment. This review was performed as a followup to an early surveillance, MP1-P-97-011, which identified that the Fix It Now team was not appropriately writing CRs for adverse conditions and improvements as required by RP-4.
 
Surveillance MP1-P-97-018 resulted in a CR concerning the inappropriate use of the trouble reporting (TR) system to identify adverse equipment conditions.
 
As a result of the NRC inspection activities concerning the use of TRs verses CRs, CR M1-97-1119, was initiated and identified that multiple site deficiency identification programs existed at Millstone. The implementation of the these other deficiency reporting processes could circumvent the RP-4 corrective action process. At the end of the inspection period the licensee was evaluating the administrative controls and implementation of these other deficiency programs.
 
Self Assessment The licensee performed a station wide self assessment that included the corrective action program as a common area to be assessed. The preliminary findings included many of the same issues identified in this report; however, the assessment was not finalized at the end
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D. Mcdonald, PM, SPO, NRR P. McKee, Deputy Director of Licensing, SPO, NRR L. Plisco, Chief, SPO, NRR S. Reynolds, Technical Assistant, SPO, NRR t
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inspection Program Branch (IPAS)
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DOCUMENT NAME: 1:\\ BRANCH 6\\REPLYLTR\\9702 REP To seesive e copy of this document. Indsete in the boa: *C" = Copy without attachment! enclosure
1 of the inspection period. In addition, a " Millstone Unit Comparative Assessment Readiness for Restart," performed by nuclear oversight, also identified problems with the corrective
'E' - Copy with attachment 4nc40su,e
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l action process. The most significant assessment was that "the threshold for CR initiation on Unit 1 is too high, thus preventing adequate corrective action investigation of the issues."
 
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OfflCE Rl/ ORS
Conclusion Overall, the imp 6mantation of procedure RP-4, Revision 4, has resulted in limited improvements in i5e corrective action process. The revision of the CR process was poorly implemented in that specific guidelines were not put in place to ensure the initiation and appropriate processing of CRs for conditions adverse to quality. However, a number of management initiatives were implemented during this period and have resulted in improvements such as corrective action plan quality. In general, improvement was noted throughout the period on many of the weaknesses discussed above. The licensee plans to revise RP-4 and develop detailed department instructions to resolve the issues discussed above, as well as many other issues identified in their self assessment.
[E Rl/ ORS)/4 / l Rl/DRP-lE I
 
NAME-JFuria nny JWhite#"
The interface between RP-4 and other lower tier deficiency reporting processes and the proper implementation of those processes is unresolved (URI 245/97-02-02) pending the licensee's further evaluation and implementation of corrective actions.
J0urry u s DATE 08/05/97 08/nj /97 08//<//97 08/
 
/97 0FF/CIALRECORDCOPY
01.5 Initiation of Condition Reoorts (SIL 17 UPDATE)
a.
 
Inspection Scoce The inspectors reviewed the threshold at which CRs were being initiated through daily observations. This inspection activity was performed in part, as a result of previous interaction with the licensee's staff, which indicated that they were unclear on the CR threshold or did not want to initiate CRs for other reasons. These issues included cable tray deficiencies, service water system macroscopic fouling, and service water system internal pipe coatings issues. Although CRs were ultimately initiated for all of these issues, a significant number of discussions between the inspector and licensee management were necessary before these issues were put into the corrective action process.
 
b.
 
Observations and Findinas During a December 1996 meeting with the licensee concerning the controls used to maintain isolation between the high to low system pressure interface, the inspector identified a procedure deficiency. Procedure 305A, " Operating Shutdown Cooling with Fuel Pool Cooling," allowed the use of the shutdown cooling system to cool the spent fuel pool. However, in one of the configurations specified, adequate separation between the reactor coolant pressure boundary, and the spent fuel pool was not maintained during conditions postulated to comply with 10 CFR 50 Appendix R. During a followup review, l
the procedure was verified to have been corrected; however, no CR had been initiated for i
this deficiency. The inspector discussed the failure to initiate a CR for the deficient
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condition with the licensee's staff; however, at the end of the inspection period the licensee had not initiated a C _
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CR M1-97-0855, initiated on April 23,1997, identified that on February 4,1997, an NRC commitment related to safeguards information had not been properly implemented.
Although the condition was identified by a security supervisor, observed by a nuclear oversight representative, and reported to two levels of management and an employee concerns representative, no CR was initiated. This CR and an earlier related CR were initiated as a result of NRC inspection activities. The previous CR, M1-97-0580, initiated March 25,1997, discussed the safeguards issue, but did not address the delay in identifying the problem. Further, when this CR was initiated the date of the event was listed as March 25,1997, thus indicating the event had just occurred and there was no delay in initiating the CR.


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CR M1-97-0694, identified that NRC inspectors observed a security officer improperly performing personnel searches. This observation occurred during a routine security inspection in early February 1997; however, the CR was not initiated until April 1997 by licensing personnel, when the NRC report was issued. Although prompt corrective actions were implemented to resolve improper search concern, this issue was not put into the
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licensee's corrective action process through the initiation of a CR. At the end of the inspection period the licensee had,.not initiate a CR for the failure to initiate the CR following identification of the security search issue.
 
CR M1-97-0842, identified that two fuel assemblies stored in the spent fuel pool did not agree with the computerized tracking systern or the special nuclear material records. The CR was initiated on April 22,1997; however the discrepant condition was identified several months earlier. Although a CR was promptly written when the reactor engineering supervisor became aware of the problem, at the end of the inspection period, the licensee had not initiated a CR on the several month delay in identifying the discrepant condition.
 
CR M1-97-0689, identified a breach in the gas turbine enclosure which provides a barrier for the CO2 fire suppression system. The inspector determined that the condition had been previously identified, approximately 10 months earlier, but was not put into a corrective action process.
 
CR M1-97-0507, identified that CRs were not being generated for adverse conditions or improvements identified during work performed by the Fix-It-Now group. This CR was originally assessed as a level 3 issue, indicating that the failure to initiate CRs consistent with RP-4 requirements was an enhancement and not an adverse condition. Subsequently, the licensee found that one of the specific deficiencies used as an example of the problem was not a valid issue. Corrective actions were implemented to resolve the second example; however the broader problem of not appropriately initiating CRs went unaddressed. The licensee upgraded the CR to a level 2 issue.
 
CR M1-97-0975, identified that during a review of conditionally released position papers, licensing commitments were inadequately addressed and resulted in a conflicts associated with systems or components described by the FSAR. However, these discrepancies were not identified via a unresolved item report (UIR) or CRs as appropriate.
 
CR M1-97-0688, identified unacceptable indications on a recirculation system weld. The shift manager determined that the condition had no effect on operability and reportabilit.. - --..-...
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The CR was subsequently presented to the management review team (MRT) and
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operability and reportability were not questioned. The engineering representative accepted the assignment to resolve the CR as a level 2 issue. The inspector discussed the issue a
with the engineering representative at the MRT and other engineering personnel, and
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determined that the issue may be reportable depending on the size and depth of the
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cracks, which had not yet been determined. The inspector discussed this assessment with i
the licensee's staff and the concern that implementation of the CR process in this case
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missed a potential operability /reportability issue. At a subsequent MRT meeting, an engineering representative discussed the issue and the two barriers which failed to catch the potentially reportable issue. However, following a discussion of whether a second CR was appropriate to address the missed operability /reportability assessment, the licensee i
elected to address the process issue via the existing CR. A subsequent review determined
that the missed operability /reportability assessment was not identified in the existing CR, nor was a new CR generated. The licensee initiated a CR to address the missed reportability evaluation generically; however, the CR initiated did not discuss the specific
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events referenced above, instead it discussed similar issues and referenced several other i
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CR M1-97-0621 identified the lack of technical specification requirements for gas turbine i
battery testing. The issue,was identified on February 1,1997; however a CR was not
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initiated until March 27,1997. The licensee attributed the delay in initiation to a personal
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error. In addition, a number of other CRs delayed by three weeks or more were attributed i
to mis-communications and the thought that CRs were already initiated to address the issues that were identified.
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C5 M1-97-0762 identified disconnected tie rods in a safety related heat exchanger. The
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CR was determined to be not reportable based on additional tie rods and that the heat
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exchanger tubes provided adequate support to the heat exchanger internal components.
l The shift manager that reviewed the CR accepted the position without challenge.
j However, based on discussion with the licensee staff this conclusion was not supported by j
an engineering evaluation. The engineering staff stated that they planned to analyze the condition and determine if it effected operability or was reportable, but during a subsequent inspection they determined that the tie rods were in place and there was no
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j deficient condition. However, the RP-4 controls to assure timely operability /reportability evaluations were not implemented and licensee management was unaware that the condition described by the CR may represent a significant historical deficiency.
I Subsequent to a discussion with the inspector, the licensee initiated a second CR to address the missed operability reportability evaluation.
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CR M1-97-0805 identified a potentially degraded backup air source to the diesel generator starting air system. The issue was determined to be not reportable since the validity of the problem was unknown. The CR stated " if the condition is determined to actually exist, a CR should be written to document the condition and a reportability determination initiated at that point." CR M197-0497 identified seven Millstone Unit 1 safety related actuators that were susceptible to failure as discussed in an NRC information notice. The issue was determined to have no actual or potential effect on operability or reportability. The CR stated "if any diaphragms are found with the wrong sizing during the investigation, separate CRs will be written to address specific operability /reportability reviews." Based
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on discussions with the corrective action manager, these conditions should have been promptly evaluated under the original CR consistent with the expectation of a 24-hour investigation time interval. RP-4 does not allow the latitude to delay addressing operability /reportability issues.
In response to the inspectors concerns that the licensee's staff was not consistently initiating CRs for significant conditions adverse to quality, Nuclear Oversight surveillance was initiated at the request of Unit 1 management. The objective of the surveillance was to assess the corrective action initiation process through questionnaires and interviews.
The surveillance identified that the majority of personnel were adequately identifying problems and writing CRs. However, the surveillance also found that some personnel are reluctant to write CRs for various reasons such as, the types of items that are reportable are unclear, procedure use identification was poor, and training received to execute the program was not standard or clear among groups. A CR was subsequently initiated to address these issues.
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Conclusion i
Condition reports are not being initiated consistent with the program requirement described in procedure RP-4. Based on discussions with the licensees staff, the number and j
significance of some of the examples either not reported, reported after NRC prompting or l
delayed without alternative reasons, there appears to be some reluctance to initiate CRs.
Several deficiencies were also noted in the initial operability and reportability screening for a number of the CRs reviewed. Specifically, three examples were identified in which the issue identified was not promptly evaluated consistent with the expectations applicable for potential operability /reportability issues. In two of the cases, the licensee's staff
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documented that if a deficiency was identified during the CR closeout investigations, that resulted in inoperable equipment, another CR was to be written. This approach circumvents the RP-4 and other controls that ensure prompt evaluations of deficiencies that could adversely affect operability or may require prompt reporting to the NRC.
U103 Operations Procedures and Documentation 03.1 NGP 2.25, Reportability Determination and LER Processino a.
Inspection Scone (71707)
The inspector reviewed the training and implementation process for Nuclear Group Procedure, (NGP) 2.25, "10 CFR 50.72,10 CFR 50.73, and 10 CFR 50.9(b) Reportability Determination and Licensee Event Report Processing," revision 10. The procedure revision incorporated and expanded guidance for reportability determinations by the inclusion of a revised version of "NU Reporting Guidance" (Redbook) as an attachment.
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Observations and Findinas NGP 2.25, revision 10, became effective on April 23,1997. During the control room walkthrough that morning, the inspector discussed the procedure change with the shift
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managers to ensure that he was aware of the new procedure. This procedure had a direct l
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Nuclear Energy m,,one sa, ro.n swoo Nonheut Nuclear EnerFy Company P.O. Bos 128 Weierford. CT 06385-0128 (860) 447 1791 Fu (860) 444 4277 The Northeast Utihties Systera JUL 2 51997 Docket tios. 50-245 50-336 50-423 i
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B16619 Re: 10CFR2.201
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U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Millstone Nuclear Power Station, Unit Nos.1,2 and 3 Facility Operating License Nos. DPR-21, DPR-65, NFP-49 Reply to a Notice of Violation Inspection 50-245/97-02: 50-336/97-02: 50-423/97-02 in a letter dated June 24,1997,W the NRC transmitted the results of an inspection conducted at the Millstone Station from March 11,1997, to May 19,1997. The NRC
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impact on the operation staff since they perform the initial review for reportability for any condition report that is processed through the control room. The shift manager informed the inspector that he was aware of the procedure change but as of yet had not received
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any training on it. Discussion with the operations manager indicated that the shift managers were going to receive familiarization training that evening, at the weekly shift manager meeting. A review of the " Documentation of Training Requirements," section 3, for this change, indicated that only familiarization was required and it was not needed prior
Inspection Report concluded that Northeast Nuclear Energy Company (NNECO) failed to properly impleme..' our rad;otion protection program as demonstrated by having five instances of personnel entering the RCA without wearing a functional electronic dosimeter or TLD, These included one instance at Millstone Unit No.1, three instances at Millstone Unit No. 2, and one instance at Millstone Unit No. 3.
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to the effective date of the new revision. The methods to provide familiarization included:
department meetings, pre-shift briefing, pre-work briefing, or document acknowledgement
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During discussions concerning the appropriateness of only familiarization training for this procedure revision, the inspector was informed that previous Revision 9 of this procedure had been initially approved by SORC with an effective date of March 7,1997, but subsequently postponed implementation due to formal training not being completed. This revision had already been distributed, when on March 6, the plant staff discovered that the
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training had not been completed. Revision 9 of NGP 2.25 was never formally issued.


Revision 10 was approved by SORC on April 16, following station reviews, a detailed independent review, and a quality assurance review. At that time, the training required for implementation was reduced from formal training to familiarization training "with no impact on effective date." The inspector discussed this issue with the licensee personnel responsible for procedure implementation and could not determine why Revision 9 required formal training and why that training was not completed. Additionally, there was no record to verify that familiarization training for Revision 10 was completed as required.
On behalf of Millstone Unit Nos.1,2, and 3, Attachment 1 provides NNECO's reply to the Notice of Violation pursuant to the provisions of 10CFR2.201.


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Conclusion The inspector concluded that the process for training and/or familiarization prior to the implementation of a procedure revision is not clearly defined, in addition, in the area of familiarization training, there is no record to ensure completio'n of this type of training.
This issue will become more significant as the unit completes its design basis reconstruction and a large number of procedures will require revisions. This issue will remain unresolved pending completion of additional NRC and licensee review (URI 245/97-02-03).
U106 Operations Organization and Administration 06.1 Overtime Controls for Operations Personnel The inspector viewed the overtime controls and records for the operations department personnel during the first quarter of 1997. NGP 1.09, " Overtime Controls for Nuclear Group Pe. sonne," states that affected plant staff shall verify proper authorization has been
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obtained prior to exceeding any overtime limits. "Affected plant staff" is defined as plant staff who perform safety related functions such as operators, health physics personnel, chemistry personnel, key maintenance personnel, and the first line supervisors of these personnel. The initial review of the time sheets from that period indicated approximately 6 individuals had exceeded the overtime limits without proper authorization. The Operations
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* Wayne D. Lanning to Bruce D. Kenyon,'NRC Combined inspection 50-245/97-02; 50-336/97-02; 50-423/97-02 and Notice of Violation," dated June 24,1997.
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Manager provided this additional information to the inspector, which indicated that those individuals had not performed safety related work, and therefore, were not subject to NGP i
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j The inspector noted that an operator, working in the operations work control center, had
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exceeded the overtime limits, including working an 18 hour day. The inspector was
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informed that there was some discussion about whether or not NGP 1.09 applied to this j
 
individual since he was not working in the control room at the time. While he was not i
actually manipulating equipment that provided a safety-related function, he was involved
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an "affected plant staff" and completed an authorization to exceed overtime limits prior to
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exceeding the established limits. The authorization stated that "no manipulation of i
equipment that provides a safety function is authorized," and was signed by the l
Department Manager and the Director of Unit Operations. The inspector concluded that j
operations personnel were in compliance with NGP 1.09 for the first quarter of 1997.


U108 Miscellaneous Operations issues (92700)
OEH224 htV,13 4
j 08.1 Use of Non OA liaht Bulbs in a OA ADolication a
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Insoection Scope (92903)
l A review of the controls for replacement of main control board indicating lights for safety related equipment was performed.
 
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Observations and Findinas l
Adverse condition report (ACR) 01447 was initiated to address the replacement of an j
anticipated transient without scram (ATWS) panel light bulb with a spare from the same i
panel. The ACR questioned the practice of using spare installed bulbs as replacements for
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active indicators. The corrective actions to resolve the ACR discussed the need to use the automated work order (AWO) process to replace indicator lamps classified as QA Category i
1 equipment.
 
Main control panel indicating lights classified as OA Category 1 equipment, are replaced by both operations and l&C personnel. Based on discussions with the operations staff, the AWO process is not used by operators to replace these indicating lights. Further, there is no alternative control to ensure that bulbs with the proper quality attributes are used.
 
Typically spare non OA bulbs maintained in the control room are used. Based on discussions with the l&C staff, the AWO process is used by the l&C group when replacing OA Category 1 indicating lights. However, when the inspector requested some examples, the licensee only found two cases since 1984,in which an AWO was used to replace control room indicating lamps.
 
A subsequent review found that numerous control board indicating lights are classified as OA Category 1 equipment. For example, core spray and isolation condenser valve indications, source range monitor trip lights, and numerous process radiation monitoring status lights. Previous evaluations had been performed and determined that numerous
 
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4 indicating lights in the main control room panels should be QA category 1, typically based on the need for that indication for post accident monitoring. The licensee initiated j
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condition report (CR) M1-97-0423 to address the issue. The licensee also plans to re-i evaluate each of the OA bulb applications and believes they can be downgraded to a non OA status, c.
 
Conclusions The licensee has not consistently implemented the AWO process or other appropriate controls for the replacement of main control panelindicating lamps that are required to be OA category 1. The bulbs in a number of these applications are typically replaced with non OA and uncontrolled bulbs. The use of non OA bulbs in a QA application is unresolved (URI 245/97-02-04) pending the licensee's review of the issue and implementation of appropriate corrective actions.
 
U1.ll Maintenance U1 M1 Conduct of Maintenance M 1.1 Unit 1 FIN Team Process (SIL 30 UPDATE)
a.
 
Inspection Scoce (62707)
In November 1996, the Unit 1 maintenance department developed and implemented a multi-discipline, independent, and self-sufficient work team called the Fix-It-Now (FIN)
Team. The purpose of the team was to perform a variety of maintenance work including troubleshooting and repair work. This process was intended to supplement the normal work control program. The inspector reviewed the FIN procedure, interviewed team members, reviewed audit reports, training records, and observed the team's interaction with other station organizations.
 
b.
 
Observations and Findinas The FIN Team consisted of a mechanic, an electrician, a maintenance planner, a health physics technician, an engineer, two instrument and control (l&C) technicians, and two operators. In addition, the Fin Team Supervisor (FTS) is a senior licensed individual who maintains responsibility for implementation of the FIN procedure, U1 WC1 A, Unit 1 Fin Process. Each FIN team member is a team qualified expert (TOE) and assumes responsibility for all job functions under their discipline or qualification. Additionally, each of the team members completed a basic maintenance fundamentals course and specific training pertaining to the FIN process. Cross-training within the disciplines is strongly encouraged. Individual training / qualifications were maintained current with the use of a training matrix for each discipline, which is updated and maintained by the FTS.
 
As stated in the FIN process procedure, the scope of the plant work performed by FIN includes all plant equipment provided that the completed work does not affect the design function of components or structures. Troubleshooting may be performed utilizing the FIN process as determined by the shift manager and the FTS, provided that the guidance in
 
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"U1 WC 1, Work Control Process," is followed. Team members are not permitted to perform welding or work that is determined to be ASME, Section XI R&R (Repair and Replacement). Since the team is independent and self sufficient, team members generate their own automated work orders (AWO) and work under a FIN team tagging system.
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The inspector attended the FIN team morning meeting. Each morning the FIN team members, led by the FTS, review the trouble reports (TRs) that were generated in the previous 24 hours and determine which items can be performed by the team. TRs on related equipment were grouped together in order to improve efficiency. The FTS attended the unit work control morning meeting and informed the group which TRs would be worked that day by the FIN team.
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Since the implementation of the FIN team, a number of assessments have been performed on the process. FIN team process assessment are conducted by the team members each Friday and provide a critical, detailed look at the previous weeks activities. Worker Observations Checklists are completed by the FTS, at a minimum of ten per month. In March 1997, the nuclear oversight group performed a surveillance to assess the FIN work control process. This surveillance resulted in procedural changes that included: 1) a clarification of the work scope to include repairs, as well as replacement; 2) a change to i
the FIN tagging process to allow use of all tags instead of only using blue tags; and 3) the removal of the 24-hour requirement for FIN work. In April 1997, a self-assessment report was completed as part of the Unit 1 self-assessment program. One enhancement to the team, which was identified in the assessments, was the need for a dedicated procurement individual to handle parts acquisition for the team. This function was bein0 performed by the team planner and was inhibiting his overall effectiveness. At the end of the inspection period, a procurement person was added to the team.
 
c.
 
Conclusions The licensee has successfully implemented the FIN team concept at Unit 1 by establishing a multi-discipline, independent, and self-sufficient work team. This team has made a positive contribution to the work effort, completing over 1000 AWOs since the team was implemented in November 1996. A significant number of team process assessments, worker observations, and a self-assessment on the team have resulted in improvements in the process. The concept of cross-training within the disciplines on the team was considered a strengt _
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i1 U1 M8 Miscellaneous Maintenance lasues
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E M8.1 (Uodate) Unresolved 50-245/96-06-02: Soent fuel Pool Tri-Nuclear Filter Removal (SIL 37 UPDATE)
a,
'Insoection Scoce (92902)
On July 16,'1996, maintenance and health physics personnel were attempting to remove a portable "Tri-nuc" filter assembly from the spent fuel pool floor when a 1/8 inch wire rope, attached to the filter assembly, caught on the bottom of three used control rod blades that-were stored along the east wall of the spent fuel pool. This caused the control rods to move, resulting in five control rods shifting position, moving away from the wall clustering together, and coming to rest against an adjacent spent fuel storage rack. On October 1,
-1996, the inspector observed the pre-job briefing for the Tri-Nuclear filter removal. As documented in NRC Inspection Report 50-245/96 08, Section U1.M1.1, the inspector
: concluded that the maintenance activities associated with the restoration of control rod blades and the removal of a Tri-Nuclear filter assembly from the spent fuel pool were well e
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planned and carefully executed. Team work and procedure' adherence was emphasized by a strong management presence throughout the work. During this inspection period the inspector reviewed two issues concerning management's intervention in the adverse-condition report (ACR) and the event review team (ERT) processes, following the filter removal event.
 
b.
 
Observation and Findinos Following the July 16,1996 event, senior management identified a potential weakness concerning a lack of radiological data and information regarding to the contaminated individuals during that event. Six of the eight individuals involved in the evolution were contaminated as a result of the filter removal event. They were successfully decontaminated and whole body counts indicated no internal dose was received. At that time, the Unit Director asked a health physics (HP) supervisor to document this issue in an adverse condition report (ACR). The ACR was written on July 23, by the HP supervisor, and submitted to the control room for processing. The following day, the HP supervisor was off and when h'e returned to work, he was informed that the Unit Director had rewritten the ACR to better document his concern. Interviews conducted by the inspector with the HP supervisor had indicated that he was surprised that no one had informed him that his ACR was being changed until he returned to work the following day.
 
The inspector reviewed both versions of the ACR and determined that there was no safety significant changes between the original and the final ACR. ' The original stated, in part, that " Senior management was unaware that the measured contamination on the 6 individuals was by industry standards considered insignificant, and was not required to be reported." The final version stated "A mechanism to communicate radiological statistical data and Key Performance indicators, on a regular basis from the Unit 1 HP Department to Unit 1 management, does not exist. As a result, Unit 1 management may not have all the necessary radiological data available at any given time. This creates the potential for actions to be taken without all the relevant facts being known." The inspector reviewed the revision of RP4, Adverse Condition Resolution Program, in effect at the time of the
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event. While the procedure is silent as to when an ACR can be changed, it does state that the supervisor shall review the ACR for completeness, "Is the problem statement clearly written to provide management and future reviewers with sufficient information to fully understand the nature of the issue?"
In this case, the inspector concluded that there was clearly an opportunity for better communications between the Unit Director and the HP supervisor. The HP supervisor was not aware that the ACR was changed, and may not have wanted to remain as the initiator of record on the revised ACR. The supervisor was given the opportunity to review and sign the revised ACR when he returned to work the following day, which he did.
 
The inspector reviewed a second issue dealing with control rod entanglement, which concerned the ERT process for documenting results, as well as the appearance of n anagement's influence over those results. The ERT was formed to perform a root cause investigation, the scope of which was to determine the root cause and causal factors for the Tri Nuclea event, and to recommend corrective action that would prevent recurrence.
 
DraR reports and a final report were issued between July 26 and August 27,1996. Each
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time a draft report was issued it became longer and more detailed following comments
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from plant rr anagement. The inspectors were concerned about the team remaining independent of line management during their investigation. Interviews were conducted with etch of the ERT members to determine what influence, if any, management had over j
the ERT results. The inspectors were informed, by the team leader, that the draft reports were more like a briefing paper meant to update management on the progress of the team.
 
He statad that they were never meant to be a final report, but that he felt compelled to give them "something" each week. The consensus of the group interviewed was that management was looking for additional infoimation after each draft was completed. The feeling was that as more facts about the event were identified, more questions were being asked. They stated that the scope of their review kept increasing. No one felt that management was trying to adversely influence the outcome of the review. However, the team stated that they felt rushed to get done as early as possible, particularly as the scope of the review increased and more time was needed to complete the work.
 
The inspectors concluded that the ERT maintained their independence from line management, and the results stated in the final report were the conclusions of the team and not the result of management's preconceptions or influence. The inspectors did note, however, that the practice of issuing draft reports, or in this case briefing papers, lead to the perception of management influence over the teams findings and conclusions.
 
Additionally, the insnector concluded that the team members lacke,d formal root cause methodology training. Management should also be sensitive to any perceived urgency on the part of ERT members to get resuits quickl.--
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l U1.Ill Enaineerina U1 E1 Conduct of Engineering E1.1' Leak Rate Testina of the Primary Containment a.
 
Insoection Scoce (92903)
Licensee event reports (LER) 50-245/96 26 and 96-46 contained discussions of various system configurations that did not allow piping to be drained adequately for local leak rate testing (LLRT) per 10 CFR 50, Appendix J. Additional discrepancies involving pressurization of valves in a nonconservative direction, and failure to test certain containment penetrations also were discussed. The inspector reviewed the following documents with regaid to the conduct of containment leakage rate testing at Millstone 1:
Millstone Unit 1 Technical Specifications
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LLRT procedures
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Piping and instrumentation diagrams (P&lDs) and system drawings
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Letters and other documents pertaining to the Systematic Evaluation Program (SEP)
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and 10 CFR 50, Appendix J program commitments Licensee Independent Root Cause Evaluation of Millstone 1 Feedwater System
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Configuration Quality Assurance Audit of 10 CFR 50, Appendix J program
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Operations Department memoranda and Engineering Work Requests
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10 CFR 50, Appendix J Program Review - Testing Program Requirements, General
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Physics Corporation, dated October 28,1996 b.
 
Observations and Findinas Feedwater Check Valves 1-FW-9A(B) and 1-FW-10A(B)
In LER 96-26, the licensee documented that the feedwater system configuration did not allow water to be drained completely to expose the isolation valve seating surfaces to the LLRT medium (air). This condition is contrary to Section ill.C.2(a) of 10 CFR 50, Appendix J, which requires that valves, unless pressurized with fluid from a seal system, shall be pressurized with air or nitrogen. Failure to perform a valid LLRT results in inability to demonstrate primary containment integrity per Technical Specification 4.7.A.3.
 
The containment isolation provisions of feedwater penetrations X-9A and X-98 consist of two check valves in series; valves 1-FW-9A(B), respectively, in the reactor building steam tunnel outside of the primary containment, and valves 10FW-10A(B), respectively, inside the drywell. The valves are 18-inch,1500 psi, Anchor-Darling, carbon steel, check valves with resilient seats. This configuration does not meet the containment isolation provisions of 10 CFR 50, Appendix A, General Design Criteria 55 and 56, which require at least one check valve inside the containment and a remote manual isolation valve outside of the containment.
 
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(n 1983, the NRC evaluated the configuration under the Systematic Evaluation Program, and accepted the use of two check valves in series,in part, because of the LLRT l
provisions of Appendix J. (Refer to Section 4.20.6 of NUREG 0824, Integrated Plant I
Safety Evaluation - Systematic Evaluation Program for Millstone Unit 1.)
 
The inspector walked down the feedwater system piping and reviewed surveillance
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procedure SP 623.14 (in effect prior to 1981) and current procedure SP 623.141,
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Containment Isolation Valve Leak Rate Test, to evaluate the method used by the licensee to drain the piping prior to testing the feedwater check valves. Downstream of inboard valves 1-FW-10A(B), the piping was drained through a one-inch bypass line around manual isolation valves 1-FW-11 A(B). The drain path is approximately three and one-half feet downstream and two feet above the check valves. The inspector estimated that the inboard check valves thus would be sealed by about 50 gallons of water during the LLRT.
 
The piping between the inboard and outboard check valves is drained through a one-inch test connection in the steam tunnel. The test connection is located on the mid-plane of the feedwater piping. As a result, approximately one-half, or nine inches, of the outboard valve seating surfaces remained sealed with water during the LLRTs. The inspector determined that the draining method specified by the procedures had not changed since LLRT started at Millstone 1 in 1976.
 
The licensee's independent root cause evaluation team reviewed plant drawings and a modification package under which the feedwater check valves and certain piping sections were replaced in 1981. The licensee concluded that the system had been constructed originally with a one-inch bottom drain line about six inches downstream of inboard check valves 1-FW-10A(B). The inspector confirmed that several drawings issued prior to the 1981 modification showed the drain lines. (See Section E1.2 of this report) However, the weld sketches, drawings, and other documents in the plant design change record (PDCR 1-75-80) do not reflect the existence of the drains, and they were not identified by the licensee during walkdowns of the modification at the time. Finally, the pre-modification version of test SP-623.14 did not reflect the existence of the drain lines. The inspector noted that had the bottom drains existed, they would have been more readily accessiNe and technically correct to use during the test. The inspector concluded that, while the bottom drains may have been inadvertently removed during the 1981 modification, it was equally likely that they had never been installed in the piping.
 
The inspector reviewed test data for the feedwater penetrations for the period 1978 to 1994. Valve 1-FW-9A failed "as-found" LLRTs in 1991 and 1994. Following repairs, for which the system piping and valves would have been drained, the valve was successfully retested. Thus two valid "as-left" LLRTs were performed on this valve. However despite these valid tests, the licer;see could not demonstrate that the combined LLRT limit of 0.6 La specified by Section ll'.C.3 of Appendix J and TS 4.7.A.3.e(1)(a) was rnet due to other LLRT discrepancies. In addition, because penetrations X-9A and X-9B were not drained and venbd during the periodic crintainment integrated leak rate tests (ILRTs), the ILRT i
results cannot be med qualitatively to demonstrate the leak tight int' grity of the feedwater e
l penetrations.
 
l The inspector ncted prior opportunities for the licensee to have identified the inability to drain the feedwater lines. A Quality Assurance (OA) Department audit of the Millstone 1 l
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Commitments
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The following are NNECO's subsequent. actions which are committed to by;this l
 
response:
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R B16619 1 A station-wide trending program, which will provide a tool to assess the effectiveness of near term corrective actions for human performance, will
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l Appendix J program was documented in report OSD-91-5448, dated December 30,1991.
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be in place by September 30,1997.


The audit was performed to verify the effectiveness and implementation of the Appendix J program by (a) verifying proper establishment of containment boundaries, and (b) verifying that ILRT and LLRT procedures implement Appendix J requirements. The inspector found i
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that the auc'it scope was limited in that it did not explore whether the test prerequisites, such as system draining, were achieved or whether the test methods met other Appendix J requirements. As evidenced by the number and variety of program deficiencies identified by General Physics Corporation's 1996 review (discussed below and in Sections E1.3), the inspector concluded that the OA audit was ineffective in this respect, in assuring the program's compliance with the provisions of Appendix J.
B16619 - 2 The long term effectiveness of corrective actions will be evaluated by performing a self-assessment. This will be completed by March 31,1998.
 
In an August 8,1991 memorandum to engineering, an operator stated a need for high
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point vents to be installed on both feedwater lines in the reactor building steam tunnel to facilitate draining of the piping for LLRT. The memorandum indicated that the piping was walked down and that the issue was discussed with the system engineer. No action was taken at that time. Operations again raised the issue with engineering in memorandum MP1-OPS-93-8, Unresolved LLRT Design Modifications, dated January 12,1993. In that memorandum, engineering was requested to evaluate several deficiencies and, as appropriate, to initiate design changes. The items were identified in the memorandum either as personnel safety issues or as potentially affecting the results of LLRT. The inspector discussed the memoranda with the operations and engineering managers identified in the memoranda. The managers recalled the issues generally as involving enhancements, with no impact on the validity of the LLRTs. The inspector was unable to find any documentation that the licensee recognized the inability to drain the feedwater piping or if so, considered the condition to be acceptable through a misinterpretation of Appendix J requirements.
 
The inspector concluded that due to the inability to drain the piping adjacent to the feedwater containment isolation check valves, the LLRTs conducted since 1976 (with two exceptions) were performed with the valve seating surfaces sealed, or partially sealed, with water. This is contrary to 10 CFR 50, Appendix J, Section Ill.C.2(a), which requires that the valves be pressurized with air or nitrogen.
 
Main Steam Drain Valve 1-MS-5 and 1-MS-6 In LER 96-26 the licensee documented the inability to drain the piping between main steamline drain valves 1-MS-5 and 1-MS-6. Similar to the feedwater check valves, inability to drain the piping would invalidate the LLRT results. The licensee identified that the normal drain path specified by the procedure was to the main condenser. However, this path was inadequate because the piping is at a higher elevation than the valves. An alternate drain path via a main steam line drain level switch was used by the operators during LLRT.
 
In memoranda to engineering dated May 16,1990, and August 8,1991, an operator questioned the ability to drain the piping through the level switch. The memoranda indicated that the piping was walked down with the system engineer, but that no further
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January 12,1993) to engineering as a deficiency potentially affecting the results of LLRT.
 
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Engineering work request (EWR) 1-93-A104, dated September 13,1993, stated, "Need a low pt [ point] drain on line 4"-MD-51 - this drain is required to ensure valid LLRT results of


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> valves 1 MS-5 and 1-MS-6 and to be abie to maintain secondary containment during testing." A due date of December 15,1993 was assigned to the EWR, The documented EWR resolution addressed the secondary containment implications of the testing and stated that "...the present method requires careful coordination to take advantage of proper plant
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conditions when they occur." No reference was made regarding the ability to drain the
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piping between the isolation valves. The inspector discussed the memoranda and EWR
.with the Operations and Engineering managers, neither of whom recalled any concern regarding the validity of the LLRT.
 
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During a system walkdown, the inspector was unable to discern a slope that would allow the piping between the valves to drain through the level switch piping. However, on the basis of a seven-inch change in the pipe elevation shown on main steam system isometric drawing 25202-20297, the licensee concluded that adequate slope existed to drain the
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prudent to verify that the slope actually existed as depicted in the drawing, and to confirm
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through discussion with the operators that no anomalies indicating water in the main steam l
drain line have occurred during the conduct of past LLRTs.
 
l In LER 96-46 the licensee reported that valve 1-MS-5 was leakage rate tested in a direction opposite to an accident condition without verifying that the reverse direction test was valid. The condition was identified during a review of the Appendix J program conducted for the licensee by General Physics Corporation. Section Ill.C.1 of Appendix J requires pressure to be applied in the same direction as that when the valve would be required to
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perform its safety function. Test pressure may be applied in a different (reverse) direction if it can be determined that results provide equivalent or more conservative results.
 
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The licensee informed the NRC in a letter dated November 14,1975, that valve 1-MS-5 (then a two-inch gate valve) was tested in the reverse direction, and that the valve
"...should seat the same regardless of direction of pressure application." In a letter dated March 3,1977, the NRC requested additional written justification for reverse direction testing at Millstone 1. The licensee responded on September 20,1978 that, for reasons unrelated to Appendix J testing, the valve would be replaced with a larger valve that would
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the valve making the results more conservative, or (b) that the seating force on the valve disk is some factor greater than the force on the disk due to accident pressure. Installation of the current valve was documented in a letter dated November 6,1980. In the letter, the licensee stated that valve 1-MS-5 satisfied the criteria. NRC review of the licensee's justification was documented in Franklin Research Center Technical Evaluation Report TER-C5257-29, dated May 26,1982. The report was appended to the NRC's Safety Evaluation Report (SER) on the licensee's Appendix J program, dated May 10,1985. The l
TER stated that the licensee should replace valve 1-MS-5 and take other actions as
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necessary to ensure that the NRC criteria for reverse direction testing are met. The 1985 l
SER concluded that the licensee's proposed actions with regard to reversing certain valves j
in order to consorvatively perform reverse direction testing met the requirements of Appendix J anr. were acceptable. The inspector was unable to determine whether the
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NRC Information Notice 94-30, Supplement 1, " Leaking Shutdown Cooling Isolation Valves at Cooper Nuclear Station," dated August 19,1994, discussed that licensee's determination that reverse direction testing of flexible wedge gate valves did not always l
meet the Appendix J requirement in that tests conducted in both directions showed that a l
reverse direction test did not consistently produce equivalent or more conservative results.
 
The licensee at Millstone 1 did not verify through testing that the results of reverse direction test of valve 1-MS-5 satisfied the Appendix J criteria. The inspector concluded l
that reverse direction tests of valve 1-MS-5 were contrary to 10 CFR 50, Appendix J, l
Section Ill.C.1. This is the first example of failure to satisfy the corrective action requirements of 10 CFR 50, Appendix B, Criterion XVI. (eel 245/97-02-05) In LER 96-l 46, the licensee committed to implement a modification and to test the valve in the reverse direction prior to startup of Millstone 1.
 
i Other Local Leak Rate Test Deficiencies
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l In May 1996 the licensee retained General Physics Corporation to develop an Appendix J
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program basis document for Millstone 1. '3eneral Physics conducted a comprehensive review of the program including test methods, procedures, technical specification
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requirements, and regulatory commitments. The results of the review were documented in a report dated October 28,1996. Subsequently, the licensee reported the deficiencies and proposed corrective actions to the NRC in revisions to LERs 96-26 (Supplement 1) and 96-46 (Supplement 3). The inspector reviewed the General Physics report and noted the following additional examples of noncompliance with Appendix J requirements.
 
l (1)
Primary containment penetrations could not be drained, or adequate assurance of full draining could not be established.
* Penetrations X-30f and X-34f Recirculation pump seal flush valves 1-RR-25A(B)
Penetration X-211 A Post-accident sample valves 1-PAS-241-PAS-25
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Penetration X-14 Reactor water cleanup inlet isolation valve 1-CU-2A
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Penetrations X-16A and X-16B Core spray injection valves 1-CS-5A(B)
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Penetration X-42 Standby liquid control valve 1-SL-7
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Penetration X-47 Recirculation loop sample valve 1-RR-37 This is contrary to 10 CFR 50, Appendix J, Section Ill.C.2(a), which requires valves to be tested with air or nitrogen.
 
l (2)
An NRC-approved exemption allowing reverse direction testing of atmosphere l
control system valves 1-AC-9 and 1-AC-12 was based on the valves being butterfly l
valves. However, they are plug-type valves for which reverse direction testing is
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nonconservative. This is contrary to 10 CFR 50, Appendix J, Section Ill.C.1, which
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would be required to perform their safety functions.
 
(3)
Type B tests by local pneumatic pressurization at a pressure not less than Pa was
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not performed and the combined leakage rate of all penetrations and valves subject to Type B and Type C tests was not confirmed to be less than 0.6 La as listed l
H. J. Miller, Region i Administrator cc-S. Dombek, NRC Project Manager, Millstone Unit No.1
below.
 
Penetrations X-25 and X-202D Integrated leak rate test pressure and flow
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- T. A Eastick, Senior Resident inspector, Millstone Unit No.1 D. G. Mcdonald Jr., NRC Senior Project Manager, Millstone Unit No. 2
connections Penetrations X-202A through H Testable packing glands on both sides of the
. D. P. Beaulieu, Senior Resident inspector, Millstone Unit No. 2 J. W. Andersen, NRC Project Manager, Millstone Unit No. 3 A. C. Cornel Senior Resident inspector, Millstone Unit No. 3
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operating arm and stuffing box of atmosphere control system valves 1-AC-1 A through J Penetrations X-25 and X-202D Flange gaskets on inboard side of atmosphere
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control valves 1-AC-9 and 1-AC-12
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Penetration X-17 Pipe flange between reactor vessel head spray valves 1-HS-4 and 1-HS-5 Penetrations X-7A through D Combined main steam isolation valve leakage
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rate determined at 25 psig was not corrected to Pa when added to the totalleakage limit of 0.6 La This is contrary to 10 CFR 50, Appendix J, Sections Ill.B.2 and Ill.B.3(a).
 
(4)
The acceptance criterion for containment air lock testing was not stated in the Millstone 1 Technical Specifications. This is contrary to 10 CFR 50, Appendix J, Section Ill.D.2(b)(iv).
 
Primary Containment Intearated Leak Rate Testina Section Ill. A.1(d) of 10 CFR 50, Appendix J requires that those portions of the fluid systems that are part of the reactor coolant pressure boundary and are open directly to the containment atmosphere under post-accident conditions and become an extension of the boundary of the containment shall be opened or vented to the containment atmosphere prior to and during the ILRT. Portions of closed systems inside containment that penetrate containment and rupture as a result of a loss of coolant accident shall be vented to the containment atmosphere. All vented systems shall be drained of water or other fluids to the extent necessary to assure exposure of the system containment isolation valves to containment air test pressure and to assure they will be exposed to the post-accident differential pressure.
 
The inspector found that prior to the ILRT in 1994, General Physics had submitted to the licensee several recommended changes to procedure T-94-1-01, " Primary Containment Integrated Leakrate Test." Based on the system lineups contained in the procedure, w
 
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General Physics listed 24 penetrations for which LLRT penalties needed to be added to the j
ILRT results. The licensee did not implement the recommendation for 20 of the i
penetrations. This is the second example of failure to identify and correct conditions l
adverse to quality per 10 CFR 50, Appendix B, Criterion XVI.
 
In its 1996 review, General Physics identified 42 primary containment penetrations involving about 18 systems in which piping was not drained and vented (or the degree of compliance could not be determined) and localleak rate test leakage penalties were not added to the 1994 ILRT results, included in the list were the penetrations (bold print below) identified prior to the 1994 test. (An asterisk denotes those penetrations in which LLRTs also were not conducted correctly.)
 
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Penetration System l
*X-9A(B)
Main feedwater
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X-10A and X-11B Isolation condenser i
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X-14 and *X-15 Reactor water cleanup a
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Core spray
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X-18 and X-19 Drywell floor and equipment drains
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X-23 and X-24 Reactor building component cooling water
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X-25 and X-202D Hydrogen / Oxygen analyzer
*X-30f and X-34f Recirculation pump seal flush
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X-35A through E Traversing incore probe
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X-36 and X-205 Drywell nitrogen
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X-37A through D Scram discharge
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X-38A through D Scram discharge
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X-39A(B)
Containment spray
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X-43 Low pressure coc".% injection inlet
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Suppression hoeder spray / PASS
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X-2008 Torus manway B
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lLRT pressure and flow test connections The failure to drain and vent the penetrations during the test or to apply the LLRT penalties to the ILRT results was contrary to Section Ill.A.1(d) of 10 CFR 50, Appendix J.
Technical Specification 4.7.A.3.a requires that containment leakage rates shall be determined in conformance with the provisions of ANSI N45.4-1972, " Leakage Rate Testing of Containment Structures for Nuclear Reactors," BN-TOP-1, " Testing Criteria for integrated Leakage Rate Testing of Primary Containment Structures for Nuclear Power i
Plants," and/or the Mass Point Method. Section 7.4 of ANSI N45.4-1972 requires that area surveys within the containment structure shall be made in advance of leakage rate testing to establish any tendencies to regional variations in temperature. General Physics found that temperature surveys prior to ILRT had not been documented and may never
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have been performed. Failure to perform the required area tempereture surveys was
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contrary to the Millstone 1 Technical Specifications. In LER 96-26 the licensee committed
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-W. D. Lanning, Deputy Director, inspections, Special Projects Office.
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to perform an ILRT prior to startup of Millstone 1. Additional commitments contained in
 
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LER 96-46 address the specific deficiencies identified above, and are to be implemerced
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prior to conducting the ILRT.
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Conclusions The inspector found several missed opportunities for the licensee to have identified and corrected significant and long-standing conditions adverse to quality pertaining to Appendix J leak rate testing. During an Appendix J program review in 1996, the licensee identified unperformed and improperly perfarmed leakage rate tests that resulted in the licensee's inability to demonstrate prirnary containment integrity as required by the Millstone 1 Technical Specifications. The megnitude and variety of problems identified were indicative of a programmatic breakdown of the Appendix J program. In the aggregate, the failure to properly implement an effective containment leak rate test program is an apparent violation of 10 CFR 50, Appendix J. (eel 245/97-02-06)
E1.2 Walkdown of Feedwater Containment Penetrations
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a.
Inspection Scooe i
The inspector walked down the feedwater system piping between the outboard isolation valves in the reactor building steam tunnel and the manual isolation valves inside the
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primary containment. The purpose of the walkdown was to verify that the system was i
depicted correctly in plant drawings, including:
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25202-26013 Operations Critical Piping and Instrumentation Diagram (P&lD)- Feedwater/ Condensate System
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25202-29119 P&lD - Nuclear Boiler (GE Dwg. 718E831)
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25202-20290 IE Bulletin 79-14 Inspection & Measurement Program -
Reactor Building Feedwater System Line No.18 25202-20002 Main Steam and Feedwater Piping Sections (Ebasco
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Services Dwg. G187497)
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25202-29103 DRAVO Corporation Pipe Fabrication Sketch E-2362-lC-48 (Ebasco Dwg. 5385-8147)
b.


Observations and Findinas The inspector found that P&lDs 25202-26013 and 25202-29119 correctly showed no bottom drain connections downstream of the check valves inside the drywell. Thus, drawings 25202-20290,25202-20002, and 25202-29103 were inaccurate in showing a drain line in these locations. The inspector also noted that one of the inaccurate drawings (25202-29103) was included in the Updated Final Safety Analysis Report as Figure 6.2-1..
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in the reactor building steam tunnel, the inspector noted a 3/4-inch line located on the mid-plane of each feedwater pipe directly opposite of the one-inch LLRT connection. The connections terminated in valves 1-FW-107A(B), a reducer,1/8-inch O.D instrument tubing, an instrument root valve, and 1/4-inch O.D. tubing. These branch lines were shown only on the P&lD (25202-26013) that is used by the operators in the control room.
The inspector also observed that valves 1-FW-107A(B) were not locked in position as is the case with other small manual primary containment isolation valves. Operations Instruction 1-OPS-10.11, " Locked Valve List," provides the administrative controls implemented by the licensee to comply with the containment isolation General Design Criteria oi O CFR 50, Appendix A, as discussed in Section 4.20 of NUREG-0824,
"Integrater' Plant Safety Assessment - Systematic Evaluation Program - Millstone Unit 1."
Valves 1-FW-107A(B) were not included either in the NUREG or the Operations Instruction, c.
Conclusion 10 CFR 50, Appendix B, Criterion Ill, " Design Control," requires measures to be established to correctly translate the plant design basis into specifications, drawings, procedures, and instructions. The inspator concluded that failure to maintain plant drawings consistent with the plant configuration and to apply procedure controls to valves 1-FW-107A(B) commensurate with those applied to similar manual containment isolation valves was a violation of this requirement. (VIO 245/97-02-07)
E1.3 Low Pressure Coolant Iniection Heat Exchanaer Foulina a.
inspection Scope in November 1995 licensee engineers identified scale deposits on the tubes of the "B" train low pressure coolant injection (LPCI) heat exchanger during a post-cleaning inspection. A similar condition subsequently was identified on the "A" train heat exchanger. On March 26,1996, Adverse Condition Report (ACR) 9801 was initiated to document the tube fouling. Since the effect of the scale on heat exchanger thermal capability was indeterminate, the licensee declared both heat exchangers inoperable. Since the plant was in the refueling mode, the inoperability of the heat exchangers had no immediate adverse safety consequences.
The inspector reviewed the Millstone 1 Technical Specification bases and the Updated Final Safety Analysis Report (UFSAR) to assess the potential impact of the scale deposits on the ability of the heat exchangers to remove post-accident decay heat from the primary containment wetwell (torus) as described in the plant design and licensing bases. The following additional documents were reviewed:
Calculation W1-517-921-RE, MP1 Low Pressure Coolant Injection Heat Exchanger
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Performance, Revision 4, dated July 22,1994 General Electric Calculation GENE-523-A013-1295, Evaluation of Post-LOCA Net
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Positive Suction Head Margin for LPCI and CS Pumps and Suppression Pool Temperature for the Millstone Unit 1 Nuclear Power Station, dated February 1995 Licenst ' Event Reports 50-245/90-014, 90-002, 91-002, and 94-13
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Millstone 1 Operating License Amendments 46 (Containment spray interlock
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setpoint change) and 84 (ANSI /ANS 5.1-1979 Decay Heat Model)
Root cause evaluations regarding LPCI heat exchanger scale deposits, dated July
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11,1996 and December 10,1996 b.
 
Observations and Findinas System Description and Desian/Licensina Basis Two redundant containment cooling subsystems are provided to remove heat energy from the primary containment following design basis accidents. During plant operation, Technical Specification (TS) 3.5.B requires both LPCI containment cooling trains to be operable, In terms of peak torus temperature and minimum available emergency core cooling pump net positive suction head, the most limiting accident is a small (.01 square foot) steamline break within the containment. Each subsystem consists of two emergency
,
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service water (ESW) pumps, one 5000 gallon per minute (gpm) heat exchanger, and two 5000 gpm LPCI pumps. When LPCI is initiated, an open heat exchanger bypass valve injects 10,000 gpm to the reactor vessel for core floodup. When the reactor core is at least two-thirds covered, reactor vessel level is stable or increasing, and containment sprays are terminated (at 9.0 psig in the drywell), the LPCI system is switched manually to the containment cooling mode by shutting tha heat exchanger bypass valves. Due to flow-induced vibration, LPCI flow through the heet exchangers is limited in the emergency operating procedures to 5000 gpm by stopping one LPCI pump per train. During containment cooling, LPCI flow may need to be throttled to ensure adequate net positive suction head (NPSH) to the LPCI and core spray pumps as the water in the torus heats up j
and containment pressure decreases. Consequently, in order to maintain a 15 psid differential pressure between the LPCI and ESW systems (to prevent release of radioactive i
material to the environment due to tube leakage), ESW flow may elso be throttled.
The LPCI heat exchangers are vertically mounted, single-pass, shell-and-tube heat exchangers with LPCI flow through the shell and ESW flow through the tubes. The heat exchanger duty described in Section 6.2.1.1.3 of the UFSAR is 40 X E6 BTU / hour at 5000 gpm each of LPCI and ESW flow, shell-side inlet temperature of 165 F, and ultimate heat sink temperature at the TS maximum of 75 F. Per UFSAR Tabk,6.3-4 and the heat exchanger manuf acturer's data sheet, a design fouling factor of.0005 is assumed. The fouling f actor is a typical design value for saltwater derived from industry (TEMA)
standards.
Prior to initial plant operation, the design-basis peak torus water temperature was 165 F, and LPCI and core spray system piping and components were analyzed and qualified to this value. Prior to commercial operation, FSAR Amendment 18 raised the peak torus water temperature limit to 203 F in November 1969, and this value is reflected in the basis of TS 3.5.B. The basis states that "...the heat removal capacity of a single cooling loop is adequate to prevent the torus water temperature from exceeding the equipment temperature capability which is specified to be 203oF. It also provides sufficient subcooling so that adequate NPSH could be assured without reliance on containment pressure except for short intervals during the postulated accident." The licensing basis remained at 203oF until the licensee completed more refined thermal-hydraulic analyses of
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1 LPCl/ESW system performance and re-evaluation of peak torus water temperature in 1994-1995. Operating license amendment 84 (dated July 24,1995) authorized the l
' licensee to use the ANSI /ANS Standard 5.1-1979 decay heat model for post-LOCA l
containment cooling analysis. Using this model, a new peak torus water temperature of 194.4 F was calculated. The inspector observed that the analysis assumed that five
!
percent of the LPCI heat exchanger tubes were plugged, and that LPCI pump performance was degraded to the maximum amount (10 percent) permitted by the inservice test program.
 
Historical Operability Issues Millstone 1 originally was designed with two heat exchangers per LPCI train, providing a single train heat removal capacity of 80 E6 BTU / hour. However, the plant was constructed and licensed with only one heat exchanger per train. As a result, the LPCI heat exchangers historically have had very little margin with respect to design-basis capability.
 
On September 8,1990, the licensee shutdown Millstone 1 when both LPCI heat exchangers were decle.ed inoperable. An inconsistency existed between the emergency operating procedures, which specificd maximum LPCI flow of 10,000 gpm, and the heat exchanger design limit of 5,000 gpm. In the short term, administrative limits (lower than those permitted by the TS) were placed on drywell, torus, and ESW temperatures. A TS amendment (No. 46) that increased the containment spray permissive interlock setpoint from 4.5 to 5.5 psig to 9.0 to 10.0 psig was approved by the NRC to ensure adequate LPCI pump NPSH An interim containment analysis conducted by General Electric Company (GE) calculated a peak torus water temperature of 209oF. In April 1991, using design-basis assumptions for drywell, torus, and ESW temperatures, and a revised hydraulic model, GE preliminarily calculated a peak torus temperature of 205 F. On December 27,1991, another GE analysis for throttled LPCl/ESW flows predicted a peak torus water temperature of 205.7o assuming a heat exchanger ESW inlet temperature of 72 F (2oF less than the TS maximum). GE completed post-LOCA containment analysis DRF-T23-00642 in November 1992. The analysis concluded that the peak torus water temperature was 206.8 F for the limiting accident.
 
In March 1994, the licensee completed hydraulic modeling and analysis of the LPCl/ESW systems in support of NRC Generic Letter (GL) 89-13, " Service Water System Problems Affecting Safety-Related Equipment," The analysis indicated that ESW flow may be less than previously assumed in the containment analysis; that is, that the required 15 psid differential pressure between the LPCI and ESW systems might not be maintained. The analysis was predicated on a descending spiral of throttling LPCI flow to maintain adequate pump NPSH resulting in the need to throttle ESW flow to maintain the required differential pressure. This in turn would increase torus water temperature requiring additional throttling of LPCI flow, et cetera. The licensee imposed an administrative ESW temperature limit of 60 F, and in May 1994 submitted to the NRC a license amendment request to remove the 15 psid requirement (thus maintaining ESW flow at 5,000 gpm).
 
The NRC wjected the request and recommended that the licensee evaluate using ANSl/ANS Standard 5.1-1979 to predict post-accident decay heat generation rate __.
 
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l In February 1995, in Order to explore corrective action options, the licensee tasked GE with re-analyzing peak torus water temperature for various conditions, with the following
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results:
l No ESW throttling (design ESW flow), no heat exchanger tubes plugged and no
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LPCI pump degradation: 206.3 ESW throttled (15 psid maintained),5% tubes plugged,10% pump flow
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degradation: > 213.3 ESW throttled, 5% tubes plugged,10% pump flow degradation, ANSI /ANS l
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Standard 5.1-1979 model: 194.4oF l
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On July 24,1995, the NRC approved operating license amendment 84, which authorized the licensee to use the ANSI Standard, and established a new licensing basis torus water temperature limit of 194.4 F.
 
From September 1990 to July 1995, Millstone 1 was operated with predicted peak torus water temperature in excess of the plant design and licensing basis limit of 203 F. On j
mtwo occasions it became necessary to impose administrative limits more rostrict:ve than -
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those permitted in the TS in order to maintain the maximum torus water temperature below -
the higher analyzed values. Operability determinations were needed to permit continued power operation with unqualified piping, pipe supports, and emergency core cooling components (LERs 91-02); core spray and LPCI pump motor cooling deficiencies; potential pump cavitation; and inability to maintain a 15 psid LPCl/ESW differential pressure (LER 94-13). Although the licensee kept the NRC informed in each instance, in none of these cases did the licensee perform a safety evaluation of procedure changes, administrative limits, or exceeding the plant licensing basis per 10 CFR 50.59 to determine if an unreviewed safety question existed. The inspector concluded that an unreviewed safety J
question did exist in that the margin of safety as defined (for peak torus water temperature) in the basis for TS 3.5.B was reduced. Extended operation of the plant in this condition was an apparent violation of 10 CFR 50.59. (eel 245/97-02-08)
LPCI Heat Exchanaer Foulina Generic Letter 89-13 recommended thermal performance testing to verify the performance of heat exchangers in open cycle cooling water systems. The licensee has not performed the testing on the LPCI heat exchangers. Instead, the licensee relied on periodic inspection and cleaning, and eddy current testing (ECT) of the heat exchanger tubes each refueling outage.
 
The licensee has observed over many years tube scale deposits following cleaning (hydrolazing) of the LPCI heat exchangers. The inspectors reviewed ECT reports from
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Craemer and Lindell Engineers, Inc. (C&L) documenting heat exchanger conditions I
observed during outages between 1980 and 1995. C&L reported deposits and scaling on the inside of the heat exchanger tubing exposed to ESW, and tubes typically required hydrotazing prior to ECT in order to permit the passage of inspection p;obes. Some tubes were found blocked or restricted such that smaller probes had to be used to conduct the
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inspections. A notable example involved the "B" heat exchanger in December 1995 where C&L documented a "...significant amount of scale and deposits..." in the tubes, and recommended monitoring to ensure that the fouling was not affecting overall heat exchanger efficiency. In 19ES, C&L stated that although no tubes were found to be blocked, at some future timo a very diligent cleaning should be conducted to remove the very adherent remaining scale in the heat exchanger tubes.
 
Licensee heat exchanger performance calculation W1-517-921-RE assumes the design basis tube and shell side fouling factor of.0005 documented in UFSAR Table 6.3-4 and the manufacturer's specification sheet. The purpose of the calculation is to derive heat transfer cos.fficients for various LPCl/ESW flow conditions used by GE as inputs to the torus water temperature and pump NPSH analysis. The fouling factor is a principal parameter affecting heat exchanger capability, and is influenced by the presence of scale
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or deposits on the tube surfaces. Given the partial tube blockages and scale deposits l
observed after hydrolazing during the past 15 years, it is unlikely that LPCI heat exchanger efficiency was maintained during the plant operating cycles at the values needed to i
support the current post-accident torus water temperature and LPCI pump NPSH analysis.
 
For example, the licensee estimated that increasing the assumed fouling factor to.001 l
would reduce the heat transfer rate to 33 X E6 BTU / hour (a 17% reduction), resulting in
- higher peak torus water temperature and reduced available NPSH. There is a limit to v,hich LPCI and ESW flow can be throttled while still removing sufficient heat and maintairing an acceptable peak torus water temperature. The February 1995 GE analysis inaicated that at 213 F additional reduction of LPCI flow would be ineffective in maintaining adequate j
NPSH.
 
The inspector concluded that the licensee's practices 6d not assure that the LPCI heat exchanger capacity described in the UFSAR and the TS basis was preserved. This is an apparent violation of T9 3.5.B, which requires two independent containment cooling subsystems to be opemale during power operation. (eel 245/97-02-09)
Corrective Actions
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The licensee has hydrotazed LPCI heat exchanger tubes prior to ECT for several years.
 
However, the inspectors found that no procedure guidance existed for the conduct of tube inspections, and no acceptance criteria for fouling were provided, in addition, the inspector found that the licensee previously recognized the need for quantitative visual inspection acceptance criteria. In a memorandum discussing NRC expectations pertalning GL 89-13 programs, dated February 18,1994, the licensee stated that "Some [ industry]
approaches.. rigorously examine the design calculations and in-place construction to evaluate the margin on each of the heat exchangers and make an estimation of an acceptable level of fouling in terms that would permit a tangible surveillance limit." The licensee also stated that "...we inspect heat exchangers frequently...and qualitatively document the condition of each heat exchanger, such as: " clean". Acceptance criteria for these visual inspections has been questioned in the SWSOPIs (NRC service water system operational performance inspections)." The inspector reviewed the root cause evaluations performed by the licensee under ACRs 9018 and M1-96-0107 in July and December 1996, respectively, concerning heat exchanger tube scaling concerns at Millstone 1. The licensee concluded that personnel had become accustomed to seeing tube scale and assumed that
 
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cleaning prior to ECT kept buildup to acceptable levels. Therefore, the effect of the fouling was never critically assessed by engineering. The root cause identified by the licensee was lack of a cornprehensive heat exchanger testing, monitoring, and visual inspection l
program with clearly defined acceptance criteria. The NRC independently confirmed the findings during an inspection of the licensee's GL 89-13 program and commitments documented in Combined Inspection Report 50-245,336,423/96-09. The licensee has committed to develop and implement a comprehensive heat exchanger inspection program and to test heat exchangers to establish performance baselines and verify design margins.
 
The licensee did not identify as a condition adverse to quality the potential for degraded heat exchanger performance due to tube fouling, and did not assess heat exchanger operability. This condition existed from at least 1980 until November 1995, and was the third example of an apparent violation of 10 CFR 50, Appendix B, Criterion XVI, which requires that significant conditions adverse to quality be identified and corrected.
 
UFSAR Discreoancies The inspector found that the dear:ription of the LPCI heat exchangers contained in the UFSAR is not consistent with the current design antl licensing basis for peak torus water temperature (circa November 1969). For example, rable 6.3-4, "Summarv of Low Pressure Coolant Injection Component Design Pararneters," was not updated to show that the LPCI heat exchanger shell side inlet temperature (peak torus water temperature) was 203 F (vice 165 F). The same error exists in Section 6.2.1.1.3, "Desigr> Evaluation, Primary Containment Response Pipe Breaks," which states that the conteinment cooling heat exchanger will remove 40 X E6 BTU / hour at "...the design condition of a hot inlet temperature of 165 F."
 
The inspector concluded that the licensee's failure to update the UFSAR to reflect the correct licensing basis heat exchanger inlet temperature was an apparent violation of 10 CFR 50.71(e), which requires periodic revision of the updated FSAR to include changes made in the facility or procedures as described in the FSAR. (eel 245/97-02-10)
c.
 
Conclusions The impact of LPCI heat exchanger tube fouling on the system's ability to cool the primary containment and to maintain post-accident LPCI pump NPSH were reviewed. The inspector identified apparent violations of NRC requirements pertaining to performance of safety evaluations per 10 CFR 50.59 and extended operation beyond the plant licensing basis, operability of the containment cooling system, and corrective action for heat exchanger tube fouling. In addition, failure to maintain the UFSAR consistent with the current plant licensing basis was an apparent violation of 10 CFR S0.71(e).
 
E.1.4 Core Sorav Recirculation Heatun Test l
a.
 
Insoection Scoce (37551)
l j
The inspector reviewed the preparation for a test involving the core spray system in the l
recirculation mode using normal surveillance procedures. The test was designed to determine if the core spray pumps could add sufficient heat to increase the torus water
 
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temperature for a low pressure coolant inje^. tion (LPCI) heat exchanger therma:
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performance test. The thermal performance test is required prior to plant ptarten as part of l
an NRC commitment.
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l b.
Observations and Findinos i
j On Wil 25,1997, during the daily control room walk-through, the inspector discussed
with %e :ontrol room operators a planned performance of a 48-hour coro spray pump run.
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The irgector was informed that the system was being placed in service as part of a test to deterrnine if the core spray pumps could provide sufficient pump heat to increase the
torus water temperature. Further inspection identified that the test was being controtted via a one page AWO that referec.ceo the normal sunfoiilance procedure and a
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j memorandum, dated April 24,1997, to the shift manager. The subject of the memorandum (MP1-TS-97-0099) was " Core Spray Pump Operation Technical Guidance"
and provided technical objectives, pre-start and operating conditions, and abort criteria.
The inspector questioned the lack of a special test proccdure, safety evaluation, or 10 CFR j
50.59 review / screening. The shift manager informed the inspector that they were just going to run the pumps using the noimal procedure and take some data, a special test
2 procedure wasn't needed.
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The inspector immediately discussed the issue with both the Operations Manager and the i
Director of Unit Operations. The test was terminated prior to actually placing the pumps in service. Other than the control room operators, it was not clear to the inspector that (
operation management understood what the test involved. The engineering staff did not
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clearly communicate their expectation to operations management. Condition report M1-97-0914 was initiated to document the incident, and stated that management concluded that
j a memorandum was not the appropriate vehicle for giving additional guidance to operations for the test.
l Subsequently, on May 6,1997, the inspectors had a discussion with the core spray
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system manager about the heatup test. He suggested that perhaps a troubleshooting plan
could be used to perform the evaluation, insisting it was not a test at all, but an attempt to j
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gather data on an operating system. The inspector determined that this was not I
appropriate, since the core spray system did not have a problem that troubleshooting would be tryirs to correct.
I c.
Conclusion
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The licensee planned to perform a test of the core spray system in the recirculation mode,
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using ntemal surveillance procedures. 10 CFR 50.59, " Changes, Tests, and Experiments,"
states, in part, that a licensee may conduct tests or expsriments not described in the i
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safety analyds rep 0(t without prior Commission approval, unless the proposed test or experiment involves a change in the technical specifications or an unreviewed safety question. Since a 50.59 reviev / screening had not been performed in preparation for this test, the intervention of the inspector in this case, prevented a potential violation of NRC
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requirements. The NRC is concerned that a vulnerability exists, which would have allowed the performance of an unreviewed test to occur.
 
U1 E8 Miscellaneous Engineering issues l
l E8.1 Electrical Bus Contral Power Transfer Switches
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a.
 
Inspection Scope (92903)
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The inspector reviewed the actions being taken by the licensee to address problems with the control power transfer switches.
 
b.
 
Observations and Findinas Each of the 4160 and 480 Volt electrical buses has a transfer switch that permits the control power for the circuit breakers to be supplied from one of two dc distribution panels.
 
For each bus, one of the sources is designated as the normal source and the other as an emergency source. The operation of the circuit breakers and transfer switches is controlled by Operating Procedure OP 344A,125 Volt dc Electrical System. During normal plant operation the emergency supply is deenergized by opening the supply circuit breaker at the dc distribution panel. The transfer switches tre configured for manual operation and require operator action to switch the control power from normal to emergency power.
 
During a plant walkdown, the inspector noted that all of the control power was being supplied from the normal supply and the emergency supply circuit breakers were open.
 
The licensee was in the process of developing a preventive maintenanco FM) program for the transfer switches and planned to implement the program during the next refueling outage. Engineering Work Request (EWR) 96-207 was written to develop as built drawings for each of the transfer switches and to generate specific component identification numbers. The shift manager has written EWR 97-0116 to request engineering to generate setpoint design bases information and to have Material, Equipment, and Parts List evaluations performed for each of the components. As a result of recent problems with several transfer switches, documented in condition report M1-97-0670, the licensee now plans to implement a program during the current shutdown.
 
c.
 
Conclusions The inspector noted that the two dc electrical power divisions were isolated from each other by both the contacts in the transfer switches and the open circuit breaker for the emergency source. This would prevent a failure from affecting both divisions. Also, the problems that have been experienced occurred while operating the transfer switches during the current outage. During power operation the transfer switches are not operated and the failures would not have resulted in the loss of control power to any of the circuit breakers.
 
The inspector concluded that the licensee is taking appropriate actions to address the problems with the transfer switche _
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E8.2 (Closed) LER 50-245/96-12, Containment Isolation Valve CU-2J Exceeded the Maximum Leak Rate Durino Ooeration (Open) eel 50-245/97-02-10 a.
Insoection Scope (37551)
The licensee failed to perform local leak rate testing (LLRT) on a number of containment isolation velves including the reactor water cleanup return inboard isolation valve CU-29 for a number of years following the establishment of the LLRT requirement. The failure to perform the required testing and related issues was addressed in NRC report 245/95-07 and in the attached violation for failure to perform the required LLRT. The operability of
CU-29 was discussed again in NRC report 245/95-20. NRC report 245/95-28 also l
discussed the historical operability of valve CU-29, but could not determine if CU-29 would have performed its intended function. This report also questioned the ability of containment to perform its intended function following a design basis accident together i
with a single failure of the redundant containment isolation valve, CU-28. In December of
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1995, valve CU-29 was replaced, resolving the longstanding testing and operabdity issues.
Following removal of the original CU-29, an LLRT was performed and determined that CU-29 had exceeded the maximum allowable leakage rate. In February 1996, the licensee
+. determined that the observed leakage was contrary to technical specification requirements
.
and reported the issue in LER 50-245/96 12. The inspectors reviewed the LER and associated corrective actions.
b.
Observations and Findinas A review of the design documentation, installation, and testing for the replacement CU-29 valve was performed and found to be adequate. An improved valve design was used to l
more closel/ match the typical operating conditions of the reactor water cleanup system.
A walkdown of the valve, following installation, revealed the addition of the test taps necessary for local leak rate testing. The post installation LLRT test results were found to be acceptable, In December 1995, during the cycle 15 refueling outage, the original CU-29 was iemoved and a bench test LLRT was performed. However, during the reverse flow air test, the test pressure of 43 psig could not be achieved as a result of excessive seat leakage. The licensee subsequently assumed the leakage to be in excess of 300.3 standard cubic feet per hour (scfh). The licensee stated that a(though a specific calculation was not performed, the high leakage assumption was supported by measured leakages, at test pressure, through other large bore penetrations as reported in LER 94-004. Technical Specification 4.7.A.3.e.(1)(a) requires a combine leakage rate of less than 0.60 La (300.3 scfh) for all penetrations and valves subject to local leak rate tests.
The original CU-29 valve was subsequently disassembled and degradation of the main seat seal was identified The 8!censee determined that the valve disc and seat were eroded l-such that the valve would not have prevented backflow leakage and consequently would
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not have performed its containment isolation function. Disassembly also revealed that the seat assembly had not been firmly attached to the valve body; however, the disk still had
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freedom of movement and thus the a%ity to close on reverse flow conditions.
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. Gross water leakage tests to meet inservice testing requirements had been performed
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'during the previous three refueling outages. These leakage evaluations were reverse flow
 
water tests using only the elevation head of the water in the reactor vessel and reactor
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cavity, approximately 30 psig. Although the tests were performed under different i
conditions and were only intended to verify that valve CU-29 would close, the tests also
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provided evidence that the valve was leaking for several cycles. Specifically, during the
' cycle 13 refueling outage the gross water leakage test results indicated approximately 1
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gallon per minute water leakage through CU-29. The previous two tests records only
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indicated that the leakage was less than the acceptance criteria of 1.5 gallons per minute.
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The LER stated that there was no safety consequence as a result of the event, since l
containment isolation would have been maintained via the redundant isolation valve CU-28.
 
j The LER also discussed that CU-29 would not have performed its containment isolation i
safety function if a single active failure had occurred in the second barrier CU-28. A
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review of related LERs and other information identified that other vulnerabilities existed durirg previous operating cycles that could have increased the plant's risk as a result of
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the integrated effect of these deficiencies. Specifically, ptior to the cycle 14 refuel outage, j
CU 23 was not c;ualified for harsh environments consistent with the conditions associated with e high energy line break. Additionally, the reactor water cleanup high temperature
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. isolation logic, used to detect a high energy line break, was not installed until the cycle 14 j
. refueling outage. The leak detection logic deficiency was documented in LER 94-07. The i
 
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net impact of these deficiencies could have resulted in the inability to isolate the j
. containment as a result of a high energy line break in the reactor water cleanup system.
 
j Specifically, CU-28 may not have operated as a consequential effect of the postulated
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environmental conditions in the vicinity of CU-28.
 
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-The review of related LERs also revealed that the combine leakage requirements have not been met for past operating cycles without consideration of leakage through CU 29. For example, LER 94-04 reported that the three penetrations with the most leakage, more than
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doubled the allowed combine leakage.
 
I C.
 
Conclusions
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The licensee's corrective actions for this issue, replacement of CU-29 and performance of j
the required localleak rate testing was found to be acceptable. The failure of the as-found localleak rate test and evidence of the longstanding leakage of CU-29 is contrary to j
Technical Specification 4.7.A.3.e.(1)(a), which requires a combine leakage rate of less than j
'O.60 La (300.3 scfh) for all penetrations and valves subject to local leak rate tests. This
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is an apparent violation (eel 245/97-0211) of NRC requirements.
 
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The licensee fai!ad to consider all recent discrepant conditions, related to containment integrity and evaluate the aggregate impact. Specifically, the LER characterized the
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leakage through CU-29 as a single failure vulnerability to containment integrity. However, prior to cycle 15, containment integrity would have been challenged as a result of the
;
consequential effects of a high energy line break in the reactor water cleanup system. The safety implication appears more significant than was discussed in LER 96-12. The licensee
-
is planning to submit a supplement to this LER.
 
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Report Details Summarv of Unit 2 Status Unit 2 entered the inspection period with the core off-loaded. 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 Demand for Information [10 CFR 50.54(f)] letter requiring certification by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Malfsis Report.
 
U2.1 Operatior!s U2 01 Conduct of Operations 01.1 General Comments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations to ensure that licensee's controls were effective in achieving continued safe operation of the facility while shut down. The inspectors observed that proper control room staffing was maintained, access to the control room was properly controlled, and operator behavior was commensurate with the plant configuration and plant activities in progress. In general, the conduct of operations was professional and safety-conscious.
 
However, one concern was noted regarding the clearing of a danger tag from the air start valve of the "B" emergency diesel generator before the lube oil system was filled. This is described in detail in Section U2.M1.1 below, in addition, during a containment tour, the NRC noted areas of blistering paint on the containment liner. This issue is discussed in detail in Section U2.E2.1 below.
 
01.2 Timeliness of Corrective Actions - Condition Report Backloa a.
 
Inspection Scope The NRC evaluated the timeliness in which the ficensee completed corrective actions associated with Unit 2 condition reports (CRs),
b.
 
Observations and Findinas Timeliness for completion of corrective actions has been a longstanding concern at Millstone. Having a CR backlog in itself is not a reflection of poor performance because as the threshold for writing CRs decreases, the CR backlog willincrease accordingly. The concern is the number of CRs that are not closed in a timely manner. To help provide the NRC some sense of the licensee's progress in addressing the timeliness cor c,ern, the licensee was asked to provide the number of CRs having outstanding corrective actions t.1at are greater than 120 days old. Although the NRC does not consider 120 days a level cf excellence nor is it acceptable when addressing immediate safety concerns, it does provide some understanding of licensee management effectiveness in addressing the corrective action timeliness issue.
 
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The 120-day CR backlog for January, February, March, and April, was 738,787,735,and 810 respectively. At the end of the current inspection period, there were 828 CRs greater than 120 days old that have not been closed reflecting an increase from 798 CRs at the end of the last inspection period.
 
DEPARTMENT CRs OLDER THAN 120 DAYS Operations
 
Design Engineering 258 Technical Support (System 221 Engineering)
Work Planning
 
Maintenance
 
I&C
 
Safety / Licensing
 
Other 139 TOTAL 828 c.
 
Conclusions
 
The backlog of 828 CRs that are greater than 120 days old indicates that timeliness for completing corrective actions continues to be a concern. Although the 120-day-old CR backlog has increased from 798 since the last inspection period, the total number (all ages)
:
of open CRs has declined slightly from 1335 CRs in January 1997, to 1215 CRs in April 1997, which is an improving trend. As discussed in NRC Inspection Report 50-336/96-04,
<
i timeliness and effectiveness of corrective actions is an area in which the licensee must demonstrate susiained improved performance before the NRC will allow the unit to restart.
 
01.3 Ouality of Corrective Actions a.
 
Inspection Scoce This inspection involved a collective evaluation of the 15 open items [ Licensee Event Reports (LERs), Escalated Enforcement items (Eels), Violations, and Unresolved items (URis)) that were reviewed as part of this inspection report.
 
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b.
 
Observations and Findinos For comparison purposes, the following table summarizes the inspection results of the 15 open items that were reviewed in this inspection report and the 16 open items that were reviewed in Inspection Report (IR) 50-336/96-08, which covered the inspection period from August 27 to October 25,1996.
 
Inspection
 
==Inspection Report==
Report 50-
50-336/97-02
336/96-08
Corrective Actions Acceptable and
 
12
Complete (includes Non-Cited Violations)
Corrective Actions identified But Not
 
2
Sufficiently Completed to Allow Closure
eel Created
 
-
Violation Created
 
1
URI Created
 
-
NOTE: Several LERs were administratively closed in Inspection Report 50-336/96-08
because the specific issue was being tracked by an eel, URI, or violation from a previous
report. To accurately reflect performance, these LERs were counted as an " eel Created,"
"URI Created" or " Violation Created" as appropriate. In addition, the column for Inspection
Report 50-336/96-08 totals 18 even though only 16 open items were reviewed because
the inspection of one URI resulted in 3 Eels being created.
c.
Conclusion
A comparison of the inspection results of 16 open items [ Licensee Event Reports (LERs),
Escalated Enforcement Item (EEi), Violations, and Unresolved items (URis)) reviewed in
Inspection Report 50-336/96-08 and 15 open items reviewed in this inspection report
indicates that the licensee has made some progress regarding the quality of corrective
actions. In this report, the corrective actions for 12 of 15 open items were acceptable
while only 4 of 16 were acceptable in Inspect lon Report 50-336/96-08, in this report, a
violation was issued for 1 of 15 open items while 7 Eels and 2 violations were created
associated with the 16 open items discussed in Inspection Report 50-336/96-0.
.
 
U2 08
Miscellaneous Operations issues (92700)
08.1 (Open) Escalated Enforcement item 50-336/96-08-06: Failure to Ensure
Refuelina Pool Drain Valves are Locked Open Durina Operation (SIL 9 & 34
UPDATE)
a.
Inspection Scope
The scope of this inspection included a review of Escalated Enforcement item (EEI) 50-
336/96-08-06.
b.
Observations and Findinas
Final Safety Analysis Report (FSAR), Section 6.4.3.1, which describes the operation of the
containment spray system during emergency conditions, states that the refueling pool drain
line isolation valves (2-RW-24A&B) are locked open during the operating cycle to prevent
the refueling pool from capturing water. Following a loss of coolant accident, the ability
to cool the core would be lost if a sufficient amount of inventory accumulated in the
refueling pool rather than draining
the containment sump where the emergency core
cooling system pumps take suction. Operating procedure OP 2305, " Spent Fuel Pool
Cooling and Purification System," provides instructions for draining the refueling pool
following refueling activities, and therefore, is the procedure that positions the drain valves
prior to operation. The NRC found that the refueling pool draining instructions, as well as
the refueling water purification system valve lineup (OPS Form 2305-2) leaves the valves
in the open but not locked open position as required by the FSAR.
This concern was discussed with the licensee who changed Section 5.27 of procedure OP
2305, which provides instructions to drain the refueling pool to the refueling water storage
tank (RWST), as well as the valve lineup, to lock open the valves. However, the NRC
'
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found that licensee failed to change Section 5.28 of the procedure, which drains the
refueling pool to the liquid radiological waste system. Since Section 5.28 makes no
reference to valves 2-RW-24A&B, the valves could have been left in the closed position.
The failure to change Section 5.28 is significant because this section, rather than Section
5.27, is normally the last section to be performed (thereby dictating the final position of
the drain valves) because water remaining in tho refueling pool after the RWST is full must
be drained to the liquid radiological waste. eel 50-336/96-08-06 was created concerning
the failure of the licensee to take adequate corrective actions even after being informed of
the deficient condition.
As corrective mtions, procedure OP 2305, Section 5.28, was changed (and is now Section
4.29) to enuao that valves 2-RW-24A&B are locked open at the end of the draining
operation to the radwaste system. The licensee noted that another cause of the problem
was that system drawing (P&lD), 25203-26023, " Spent Fuel Pool Cooling and Cleanup
Sy tem," did not show valves 2-RW-24A&B in the locked open position. Design Change
Notice (DCN), DM2-00-0089-97, was issued on March 24,1997, to correct the valve
positions on the P&lD. The inspector reviewed Operations Critical Drawings in the control
room and the Unit 2 work control center and verified that the DCN had been entered on
these drawings on March 27,199 _ -
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c.
Conclusions
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Licensee corrective actions to address the specific FSAR discrepancy were determined to
'
be acceptable. The broader issue associated with failure of the licensee to operate the
facility in accordance with regulations, the license, and the FSAR is the subject of the
March 7,1996, NRC 50.54(f) letter and is considered an NRC restart issue. The broader
issue regarding the failure of the licensee to effectively implement a corrective action
program is also an NRC restart issue. The proposed violation and potential escalated
enforcement action for this item is still under review by the NRC.
U2.ll Maintenance
U2 M1
Conduct of Maintenance
M 1.1 Isolation Taa Cleared Before "B" Emeraency Diesel Generator Lube Oil
System was Filled and Vented
a.
Inspection Scope
This inspection involved interviews with licensee personnel, as well as a review of the
licensee's root cause analysis associated with restoration of the "B" emergency diesel
generator (EDG) following maintenance.
b.
Observations and Findinas
On March 4,1997, the licensee was preparing to run the "B" EDG following maintenance.
During the pre-job brief, a maintenance technician noted that the danger tag from the diesel
air start valve had been cleared and the lube oil system had not yet been filled and vented.
Had an automatic start signal been received during the 45 minutes that the air start valve
tag was cleared, this could have resulted in the failure of the "B" EDG due to insufficient
lube oil to the upper crankshaft. This is significant particularly in light of the fact that
extensive damage to the "B" EDG occurred in April 1996, when several upper crankshaft
bearings failed due to insufficient lubrication during engine starts.
The licensee's root cause analysis of the March 4 event revealed that Maintenance
Procedure MP 2719K, "ELG Lube Oil System Maintenance," provided restoration steps for
filling and venting the lube oil system. However, the Senior Reactor Operator (SRO)
assigned to work control wlio was coordinating the EDG restoration failed to recognize the
need to defer clearing the air start tag until completion of the fill and vent activity. In
addition, the automatic work order process, the tagging process, and the Operations Work
Control practices collectively did not adequately control the sequencing of the fill and vent
evolution.
Corrective actions taken for this event included: (1) Operations personnel were briefed; (2)
Standard EDG work orders were revised to specify that subsystems are restored prior to
making the EDG available for operation; (3) As an interim measure, the standard EDG
tagout was changed to reflect the need for Shift Manager approval for clearing the EDG air
start valves; and (4) As a longer term measure that was already under development, the
 
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licensee plans to standardize the process for the removal and restoration of components
and systems. This includes formalizing standardized tagouts and utilization of new tagout
software.
c.
Conclusions
The performance of the maintenance technician was excellent in identifying that the "B"
EDG could automatically start, potentially resulting in engine damage. Although this event
did not involve any violation of NRC regulations, the SRO's decision to unisolate the "B"
EDG starting air prior to filling and venting the lube oil system was considered to be a
significant weakness, particularly in light of tbs f act that the "B" EDG was extensively
damaged in April 1996 as a result of insufficient lubrication during routine engine fast
starts. Although licensee corrective actions from the April 1996 EDG failure appropriately
focused on ensuring adequate lubrication during routine surveillance testing, the EDG
failure should have raised operator awareness during the March 1997 post-maintenance
restoration to ensure the diesel could not start without sufficient lubrication. The root
cause analysis for March 1997 event was of high quality and was comprehensive in
addressing not only the operator performance issues but also the work control process
enhancements associated with equipment restoration.
U2 M3
Maintenance Procedures and Documentation
M3.1 Numerous Examples of inadeauate Surveillance Procedures (SIL 8 UPDATE)
a.
inspection Scone
This inspection involved a review of NRC inspection reports and licensee event reports
(LERs) that have been issued over the last six months to identify and evaluate any trends in
licensee performance,
b.
Observations and Findinos
The review of inspection reports and LERs revealed the following 17 examples of
inadequate surveillance procedures (SPs).
LER 336/96-23 and LER 336/96-26 - Operations Form 2605A-1, " Verifying
*
Containment Integrity," failed to satisfy TS 4.6.1.1.a in that all of the required
valves were not included on the valve lineup and valves located inside containment
were being marked N/A while at power. Although this condition was initially
identified by the licensee, followup inspection by the NRC, which is documented in
Section M.8.3 of this inspection report, found that the procedure change to
Operations Form 2605A-1 was inadequate.
LER 336/96-24 - Surveillance procedures failed to satisfy the requirements of TS
*
4.3.1.1.3 and 4.3.2.1.3 for reactor protection system and engineered safety feature
actuation system response time testing. LER 336/96-24, Rev. O, discussed that the
SPEC 200 electronics were not included in the response time testing. Unresolved
Item 336/96-08-09 was created because the NRC found that portions of the circuit
 
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other than the SPEC 200 electronics were also not being tested. The licensee
issued LER 336/96-24, Rev.1, which stated that various cabling, wiring, connector
pins, interposing relays, and plant end devices were also not included in the
response time testing.
!
LER 336/96-25 - SP 2514D, " Auxiliary Exhaust Actuation System," (AEAS) failed
*
to test the interlock between AEAS and the enclosure building filtration actuation
system.
'
LER 336/96-30 - The NRC found that SP 21136, " Safety injection and Containment
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Spray System Valves Operational Readiness Test," was inadequate in that it failed
to test the high pressure safety injection pump discharge check valves in the closed
direction as required by TS 4.0.5.
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LER 336/96-35 - SP 2402P, " SPEC 200 Safety Parameters Functional Test," failed
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to test the interlock function associated with the main steam isolation system as
i
required by TS 3.3.2.1.
LER 336/96-37 - SP 2619A, " Control Room Shift Checks," did not satisfy the
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Technical Specification (TS) 4.7.11 requirement for verifying ultimate heat sink
.
temperature.
LER 336/96 38 - SP 2613A/B, " Diesel Generator Operability Tests" used an
*
inaccurate and non-conservative " Ready to Load" annunciator for timing when the.
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diesel achieved rated voltage and therefore, failed to satisfy TS 4.8.1.1.2.a.2. The
associated voltage relay was found to be miscalibrated.
LER 336/96-39 - SP 2505H, " Containment isolation Valve Operability Test -
*
Shutdown," failed to test the containment purge isolation function as required by
,
TS 4.9.10.
LER 336/96-40 The NRC identified that SP 2619A, " Control Room Shiftly Checks"
*
did not satisfy the requirements of TS 4.1.2.3.2, 4.1.2.3.3, and 4.4.1.4 for
verifying the motor circuit breaker positions of high pressure safety injection pumps,
charging pumps and reactor coolant pumps respectively.
LER 336/97-03 - SP 2618C, " Fire Protection System Smoke Detector Test," failed
*
to satisfy TS 4.3.3.7.1 (prior to 1995) or Technical Requirements Manual (after
1995) requirements associated with verifying the trip functions of components
associated with the smoke detectors.
LER 336/97-07 - SP 2605N, " Reactor Head and Pressurizer Vent Solenoid Valve
*
Operability Test," did not adequately verify flow through the vent path as specified
in TS 4.4.11.3.
LER 336/97-08 - Surveillance procedures failed to test some relays in the reactor
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protection system logic circuitry.
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LER 336/97-09 - Surveillance procedures f ailed to test the delay circuit actuation
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modules and downstream circuitry for the containment spray actuation system.
)
LER 336/97-12 - SP 2613A/B, " Diesel Generator Operability Tests" used an
*
inaccurate and non-conservative " Ready to Load" annunciator for timing when the
diesel achieved rated cpeed and therefore, failed to satisfy TS 4.8.1.1.2.a.2. The
i
licensee was unaware that the spead sensing circuitry also had a lube oil pressure
input that could cause ths " Ready to Load" light to turn on early.
LER 336/97-13 - SP 2404AK2, " Containment Gaseous Process Radiation Monitor
*
RM 8123B," failed to perform TS Table 4.3-13, Item la, Notation 2, which requires
that the operability of the associated alarm be verified. The procedure inadvertently
jumpered out this alarm rather than the alarm for the stack gaseous radiation
monitor.
LER 336/97-16 - SP 2610B, " Turbine Driven Auxiliary F9edwater Pump Operability
*
and Operational Readiness Tests," failed to run the pump for 15 minutes or start the
pump from the control room prior to entering mode 3 as regired by TSs
4.7.1.2.a.3 and 4.7.1.2.a.1.
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c.
Conclusions
Over the last six months, NRC inspection reports have discussed 17 ffRs involving
inadequate surveillance procedures. For five of the earlier LERs, the f.RC either identified
the issue or NRC intervention was necessary to achieve satisfactorv :orrective action in
the response to Violation 336/96-08-07, which addressed inader;oate containment integrity
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valve lineups, the liceasee committed to review all TS surveil!ance procedures for
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adequacy. Several more recent examples of inadequate surveillances are the result of this
commitment. Other examples are the result of reviews conducted as cart of their 10 CFR
50.54(f) effort and the reviews for Generic Letter 96-01, " Testing of !;afety-Related Logic
Circuits." The more recent examples were generally licensee-identificJ, however, these
appear to be repetitive violations and are being considered collectively as an apparent
violation. The NRC Significant Items List, Item 8, lists surveillance procedure adequacy as
an issue that the licensee must satisfactorily address prior to restart. This is an apparent
violation (eel 336/97-02-12)..
U2 M8
Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Violation 50-336/96-01-06: Anticioated Transient Without Scram (ATWSJ
System Testina
a.
Inspection Scooe
The inspectors reviewed the corrective actions implemented in response to the subject
Notice of Violatio.
.
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Docket Nos. 50-245 50-336 EQ:d23
b.
Observations and Findinas
This violation concerned the failure of the licensee to adequately establish and implement a
test procedure to ensure that the ATWS mitigation system actuation circuitry (AMSAC)
performed its function in a reliable manner. Procedure SP 24020 "ATWS Setpoint
Functional Test," Revision 3, was inadequate in that it failed to reflect changes in contact
positions that occurred as a result of system modifications. Also, on July 16,1995, the
procedure was not properly implemented in that 4 of 12 contacts that were specified for
checking the position of the AMSAC relays were not in the specified position, yet the
procedure was signed off that the acceptance criteria had been met.
Corrective actions taken by the licensee included:
Procedure SP 24020 was revised to correct the deficiencies and to clarify the
*
specific contact verifications required to be performed and documented by the
technicians.
The revised procedure was validated to ensure the system operability.
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l&C personnel involved in procedure changes received training to ensure they were
a
aware of how to use the Generation Records Information Tracking System to ensure
that the latest drawing revisions and design change notices (DCNs) are utilized
when changing procedures.
Enhancements were made to the Design Control Manual and Millstone Procedure
*
Writer's Guide.
O
The inspector reviewed the associated procedures and drawings, including the results of
the revised test, and found them to be satisfactory.
 
a
c.
Conclusions
l
The licensee's corrective actions were appropriate and had been implemented to resolve
this issue. This item is closed.
M8.2 (Closed) Violation 50-336/96-04-08: Failure to Adeauatelv Retest Solenoid Valve 2-
)
SI-618 Followina Valve Replacement
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a.
inspection Scope
!
The inspectors reviewed the corrective actions implemented in response to the subject
!
Notice of Violation.
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b.
Observations and Findinas
This violation concerned the fact that the retest of a safety injection system solenoid valve,
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2-SI-618, following its replacement in 1989 was inadequate in that it failed to identify the
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valve was inoperable due to a missing part. Other associated concerns involved working
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outside the scope of the work order, and the failure of routine surveillance tests to
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collectively verify valve operability. During the short time period this valve is opened each
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month, a portion of safety injection flow to the reactor coolant system would have been
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diverted.
The inspector verified that the licensee has taken the following corrective actions:
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Valve 2-St-618 has been repaired and retested.
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Procedure CWPC-3, " Post Maintenance Testing," has been revised to more
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clearly state post maintenance testing requirements.
Surveillance Test Procedure SP 2004P, " Engineered Safety Features
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,
Equipment Response Time Testing," has been revised to require verifying
that 2-SI-618,2-SI-628, 2-SI-638, and 2-SI-648 individually close to satisfy
 
technical specification time requirements. In addition, each valve closure is
timed.
The standard automated work orders for all 94 safety-related air operated
*
valves contain a caution that precludes disacsembly of the solenc>id-operated
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valves unless engineering is first contacted.
i
Because of many other problems in the work control process identified since
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1989, the licensee has made significant changes to their work control
process. Procedural controls, personnel training, and the establishment of a
more effective work control group has minimized the chance of work being
performed outside the scope of an automated work order.
Additional training has been given to the maintenance workers.
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c.
Conclusions
The licensee's corrective actions were appropriate and had been implemented to resolve
this issue. This item is closed,
j
M8.3 (Ocen) Violation 50-336/96-08-07: Containment Intearity Surveillance Test
i
a.
jnsoection Scope
The inspector reviewed the corrective actions that were taken in response to the subject
technical specification (TS) violation,
b.
Observations and Findinas
,
,
,
in December 1996, the licensee identified a violation of the containment integrity plant
technical specification. Specifically, surveillance procedure (SP) 2605A, " Verifying
Containment Integrity," did not include all of the applicable valves on the associated OPS
Form 2605A-1. The TS requires the valve positions to be verified at least once per 31
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days. The licensee also identified that when the survoillance was performed with the
reactor operating at power, the operators performing the procedure were annotating the
lineup as "not applicable" for the valves located inside the containment. However, the TS
did not allow for this exemption.
The licensee's corrective actions included issuance of Revision 18 to OPS Form 2605A-1
to include the valves that were previously overlooked and the submittal of a TS
amendment request to address the verification requirements for valves inside containment.
During a review of Revision 18 of the surveillance procedure, the inspector noted that in
some cases the required position was listed as OP/CL (open/ closed) or LC/OP (Locked
closed /open) without any notes or instructions to explain when or under what conditions,
the open position would be acceptable. This was the case for three of the valves added by
Revision 18 and for four valves previously included in the procedure.
The licensee informed the inspector that the reason for this change was to allow selected
valves to be operated as necessary to support plant operations, such as the operation of
shutdown cooling system while in Mode 4. However, the procedure as written lacked the
guidance to ensure that a valve that may be out of the desired position would be identified
and corrected during the monthly performances of the procedure.
The licensee acknowledged this concern and has revised the TS amendment request to
include a detailed discussion in the TS bases regarding the administrative controls for
having one or more of the specified containment isolation valves open.
The inspector also noted weaknesses in the procedure revision process in that the
personnel preparing and reviewing Revision 18 decided that a safety evaluation was not
necessary for the changes being implemented. Also, the Plant Operations Review
Committee (PORC) Cover Sheet for the procedure revision noted that the required position
for valves 2-SI 651 and 2-SI-709 were affected by the revision. However, other affected
valves were not discussed in the cover sheet. The licensee issued Condition Report M2-
97-0787 to address these concerns.
c.
Conclusions
e
The NRC concluded that procedure SP 2605A does not provide adequate direction to the
plant operators performing the containment integrity verification. This item remains open
pending issuance of the technical specification amendment and associated procedure
changes.
M8.4 (Open) Escalated Enforcement item 50-336/96-08-10 Heavy Load Concern and
Corrective Actions (SIL 36 UPDATE)
a.
inspection Scope
The inspector reviewed the corrective actions implemented in response to the subject
escalated enforcement ite __ _
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* b.
Observations and Findinas
This item addresse' the fact that although the licensee reported that Unit 1 heavy loads,
d
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as well as Unit 2 heavy loads, have been lifted over a Unit 2,480 Vac vital switchgear
'
room, neither the licensee event report nor the corrective action tracking system reflected
the need for Unit 1 corrective actions. In addition, Unit 1 personnel indicated they were
not aware of the need to change their crane operating procedures.- The failure of the
licensee'to implement adequate corrective actions to address the Unit 1 heavy load
vulnerability was characterized as an apparent violation.
The inspector reviewed the licensee's corrective actions and verified that Unit 1 procedures
MP 791.2, " Turbine Generator Major Components Laydown," and MP 790.4, " Control of
Heavy Loads;" and Unit 2 procedures OP 2352, " Crane Operations," MP 2703H5,
i
"Turbino Generator Laydown," and MP 2712B1, " Control of Heavy Loads" have been
revised to recognize and add precautions concerning the moving of heavy loads over
safety-related equipment using the turbine building cranes. As discussed in Inspection
Report 50-336/96-08, areas of the Unit 2 turbine building which are above safety-related
equipment have been clearly marked,
c.-
Conclusions
Licensee corrective actions to address the specific concern regarding the control of Unit 1
,
,
heavy loads over Unit 2 safety-related switchgear were determined to be acceptable. The
t f
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broader issue regarding the failure of the licensee to effectively implement a corrective
action program is considered an NRC restart issue and will be the subject of future of NRC
inspection activity. The proposed violation and potential escalated enforcement action for
this item is still under review by the NRC.
M8.5 (Closed) Licensee Event Report 50-336/96-16: Non-Functional Circulatino Water
Pumo Trio Function
a.
Inspection Scone
The insoectors reviewed the licensee's findings and corrective actions associated with the
i
subject LER.
b.
Observations and Findinas
in March 1996, the licensee found that the power supply to the condenser pit level
switches was incorrectly connected. This error would have prevented the automatic trip of
the circulating water pumps on high pit level in the event of a pipe rupture and flooding.
The purpose of this trip is to mitigate the rupture of a circulating water system piping to
prevent flooding of the auxiliary feedwater pumps.
The licensee corrective actions included the following:
Correction of the wiring to the level switches;
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Attachment 1 Millstone Unit Nos.1,2, and 3 Facility Operating License Nos. DPR-21, DPR45, NFP-49 i
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Development of procedure IC 2440, " Circulating Water Pump Trips Functional
Reply to a Notice of Violation NRC Combined Inspection Report 50-245/97-02,50-336/97-02 and 50-423/97-02
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Test," to perform periodic functional tests;
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Satisfactory performance of the functional test of the trip functions and;
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Addition of a note to the standard automated work order for the level switches to
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identify the need for a functional test following maintenance and included a
reference to this LER.
The inspector reviewed the documentation associated with the above noted corrective
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actions and performed a field inspection of the affected switches. No discrepancies were
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noted during the document review and the switches were found to be in good material
condition.
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c.
Conclusions
Licensee corrective actions associated with LER 50-336/96-16 were found to be thorough.
This item is closed.
M8.6 (Closed) Licensee Event Report (LER) 50-336/96-37: Ultimate Heat Sink
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Tomoerature Surveillance Te.st
a.
Inspection Scope
The inspectors reviewed the licensee findings anti corrective actions associated with the
subject licensee event report.
b.
Observations and Findinas
In December 1996, the licensee identified that surveillance procedure 2619A, " Control
Room Shift Checks," did not verify the ultimate heat sink temperature specifically as
required by the technical specification surveillance requireme The TS specifies that the
ultimate heat sink should be determined to be operable by vedpig the average water
temperature at the Unit 2 intake structure. Procedure 2619,A specifies the use of a single
instrument to monitor temperature up to 70oF. When the temperature reaches 70 F, the
procedure specifies using service water header temperature instruments located in the
turbine building. Thus, while the intent of the requirement was being met, the specific
surveillance requirement to measure the " average" temperature, "at the Unit 2 intake
structure" was not being met.
On March 27,1997, the licensee submitted a proposed revision to the technical
specifications and the technical specification bases. The revision would not change the
ultimate heat sink temperature limit of 75Y, but would clarify the temperature
measurement requirements.
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July 1997
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c.
Conclusions
 
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The NRC concluded that the licensee's submittal of the technical specification amendment
would address this issue. This item is closed. This licensee-identified technical
specification minor non-compliance is being treated as a Non-Cited Violation, consistent
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with Section IV of the NRC Enforcement Policy.
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U2.lli Enaineerina
U2 E2
Engineering Support of Facilities and Equipment
E2.1
Blisterina Paint on the Containment Wall
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a.
Insoection Scope
 
The NRC reviewed the licensee's evaluation of the blistering paint observed on the
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containment liner and its potential adverse affects during accident conditions. The
licensee's evaluation of other containment liner plate anomalies was also reviewed.
b.
Qbservations and Findinas
i
During a tour of the Unit 2 containment, the inspector noted areas of blistered paint on the
containment wall. The inspector asked the licensee if this peeling paint had been analyzed
for its effect on clogging the containment sump screen. The licensee produced Engineering
Record Correspondence ER-95-0014, (Rev.1, dated 2/9/95) which was written to address
Trouble Report No.11M2092923 that reported paint blisters i.. the coating applied to the
containment liner plate inside containment. The ER evaluated: 1) whether there would be
increased hydrogen generation due to exposed ziric-based primer; 2) possible containment
sump screen clogging due to dislodged paint during an accident; and 3) potential
containment liner plate degradation due to containment spray.
The containment liner plate is painted with a zinc-r:ch primer, which is then covered with
Phenoline 305, an epoxy paint finish coat. The ER discusses a hydrogen generation
calculation (NUSCO Calculation W2-517-1043-RE, dated 11/17/92) that had already
conservatively assumed that all of the zinc-based primer inside containment was exposed
to containment spray. Therefore, postulated failure of the blistered paint is not an
unanalyzed event and will not further contribute to the estimated hydrogen generated.
The ER also discusses the possibility of the paint chips clogging the containment sump
screen. Based on the specific gravity of the paint, expected amount of paint chips, mesh
size of the screen covering the containment sump and sump face velocity, the ER
concludes that clogging of the sump screens would be negligible. Due to generic concerns
with containment sump screen mesh size and emergency core cooling system (ECCS)
pump throttle valve clogging, the NRC has a restart item (Significant items List #22)in this
area to inspect and evaluate prior to Unit 2 restart.
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The ER further describes the zinc * rich primer being chemically resistant to alkalies. Since
the containment spray solution is slightly alkaline, the general corrosion rate of the
containment liner plate steelis negligible, and only localized pitting, at very small rates,
would occur.
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A memorandum dated March 29,1995, (DE2-95-227) discusses repainting the
containment liner plate. However, since containment liner paint is a factor in the
containment response analysis, a thorough evaluation of existing conditions should be
done with a proper safety evaluation prior to any repainting efforts. The memorandum
recommended establishing a project to fully analyze the details of a coating replacement,
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and if practical, schedule resources to recoat, replace and/or repair the coating over a
number of future outages.
A containment liner plate anomaly was also reviewed by the inspector. This anomaly was
discussed in a plant incident report written in December 1981, and described two bulges in
the same panel of the containment liner plate. An engineering report investigated the
cause of the bulges, and evaluated their existing condition with respect to future operation.
The report discussed typical loading conditions, including thermal expansion. During
normal operation, the superposition of stresses loads the containment in the hoop direction
in compression. In other words, the concrete containment tends to shrink relative to the
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containment liner plate, which would try to bulge the liner plate inward. However,
calculations show that the liner plate is stronger than the stresses involved. Therefore, this
particular panel of the liner plate was probably originally installed with a slight inward
bulge, which was allowable during construction. This panel, when subject to concrete
shrink during normal operation, would then further deflect inward, creating two noticeable
bulges in a panel of the containment liner plate.
The Millstone Unit 2 Final Safety Analysis Report, Section 5.2.4, " Steel Liner Plate and
Penetration Sleeves," describes isolated areas where the liner has an initial inward curve.
Inward deformation of the liner between anchors may occur under both operating and
accident conditions. The liner and anchors are designed with sufficient ductility to undergo
displacement to relieve the loads without rupturing under these conditions.
A Bechtel topical report also allows the containment liner plate to distort without any
detrimental effects as long as anchor integrity is maintained. The licensee confirmed that
the bulges were contained between two adjacent anchors. A magnetic particle test and a
negative pressure test of the bulge found no cracks or breaks in the containment liner
plate,
c.
Conclusion
Based on the inspector's review of the ER, the blistering paint on the containment wall
presents no apparent safety concern in its present or expected future form. The licensee is
also considering whether to recoat, replace and/or repair the paint. Bulges in the
containment liner plate wall are not abnormal occurrences and are analyzed to have no
detrimental effect on future plant operation. It does not appear that bulges are causing the
paint to blister since the blistering paint is found in other places in containment rather than
just in the area of the bulges, which are limited to two - 1' x 10' areas within the same


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section of the liner plate. The NRC has a restart item to inspect and evaluate containment
sump mesh screen size and ECCS pump throttle valve clogging.
U2 E8
Miscellaneous Engineering issues (92903)
E8.1
(Closed) Violation 50-336/95 11-01: Failure to Promotiv Identify and Correct
i
Enaineered Safeauards Actuation System Desian Deficiency
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a.
Inspection Scope (92903)
The inspectors reviewed the corrective actions implemented in response to the subject
notice of violation.
b.
Observations and Findinos
The violation cited the licensee for failing to promptly identify and correct a design
deficiency that resulted in six failures of undervoltage modules in the engineered
safeguards actuation system (ESAS).
Corrective actions taken by the licensee included returning all of the modules to the vendor
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for modifications to correct the design deficiency. Also, a root cause evaluation of the
ESAS design and control process and a self-assessment of ESAS related issues were
perfomied. The licensee has taken actions to support replacement of the ESAS equipment
whch is becoming obsolete and difficult to maintain due to the difficulties in obtaining
rep'acement parts.
Overall, the NRC had found the corrective action program to be weak and, as discussed in
NRC Inspection Report 96-04, the corrective action program must be demonstrated to be
effective prior to restart of any of the Millstone Units.
Other actions associated with the overall corrective action program included the
development and issuance of procedure RP-4, " Corrective Action Program." Revision 4 to
this procedure was issued in February,1997 in an ongoing effort by the licensee to
implement broader based improvements to the corrective action process.
The licensee has also implemented the Maintenance Rule program which should also
identify repetitive equipment problems,
c.
Conclusions
Licensee corrective actions to address the specific concern regarding the ESAS
undervoltage module failures were determined to be acceptable, and therefore this item is
closed. The broader issue regarding the failure of the licensee to effectively implement a
corrective action program is considered an NRC restart issue and will be the subject of
future of NRC inspection activity.
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E8.2 (Closed) Unresolved item 50-336/95-25-03: Enclosure Buildina Filtration System
Sinale Failure Vulnerability
a.
Insoection Scope
The scope of this inspection included a review of Unresolved item 50-336/95-25-03.
b.
Observations and Findinns
This unresolved item discussed a single failure vulnerability associated with the
containment and enclosure building purge system (CEBPS). The Enclosure Building is a
secondary containment that is credited in the accident analysis for ensuring that leakage
from the primary containment following a loss of coolant accident is directed to and treated
by the safety-related enclosure building filtration system (EBFS) prior to release. CEBPS is
a non-safety-related system in which the main exhaust fans can be aligned to take suction
from the enclosure building to reduce the temperature for personnel comfort. Unlike
CEBPS, EBFS contains charcoal filters that remove lodine, which is necessary for
maintaining offsite doses to less than 10 CFR Part 100 limits at the site boundary. The
single failure vulnerability involves the one component in CEBPS that is safety-related, the
purge damper AC-11, which is designed to close on a containment isolation actuation
signal (CI AS). Because CEBPS does not have charcoal filters,if purge damper AC-11 failed
to close due to a mechanical failure or CIAS signal failure,10 CFR Part 100 limits for
offsite doses could be exceeded.
Subsequent licensee reviews determined that the original licensing basis did not require
damper AC-11 to meet the single failure criteria. The NRC also reviewed early licensing
basis records, and found there was insufficient information available to determine whether
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single failure reliability was required during enclosure building purging operations. Due to
this uncertainty, the NRC determined that correction of this single failure vulnerability
'
would be considered a backfit. The NRC decision on whether to require the licensee to
take backfit corrective actions was based, in part, on the information the licensee provided
in Licensee Event Report (LER) 50-336/94-40-02 which stated: (1) The vulnerability only
exists while purging the enclosure building at power, which is an infrequent evolution that
is performed when the enclosure building becomes too hot for workers; (2) If damper AC-
11 failed to close, " Radiation Monitoring alarms and trends would indicate an abnormal
condition and alert the operators to take corrective actions to quickly terminate the event."
In addition, Attachment 1 of the LER discusses the operator actions that can be expected
"without procedure changes" and states that Unit 2 stack radiation monitor would alarm in
the control room and would "wll the operators of the unfiltered release condition and they
will secure main exhaust fans." The NRC reviewed this information and determined that a
backfit to correct single failuro vulnerability with damper AC-11 was unnecessary.
During the final NRC review of Unresolved item 50-336/95-25-03, the inspector reviewed
Alarm Response Procedure (ARP) 2590H, " Alarm Response for Control Room Radiation
Monitor Panels, RC-14," Alarm RC-14C, " Unit 2 Stack Gaseous," to confirm the LER
statements indicating that operators "would quickly terminate the event" by securing the
main exhaust fans. The inspector found that procedure ARP 2590H does not specifically
direct operators to secure the main exhaust fans based on the failure of damper AC-11 to
 
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close. Rather, the procedure first directs that all three main exhaust f ans be started if it is
desirable to increase dilution (The main exhaust fans take suction from various sources
such as the auxiliary building.) The procedure then directs that one or more (and possibly
all) main exhaust fans be secured as necessary to maintain the release rate below the
95,000 microCuries per second limit. The release rate is a value that is manually
calculated by :.he operators using the stack radiation monitor reading and a conversion
factor based en the main exhaust fan combination. Although all three main exhaust fans
would be secured if necessary to prevent exceeding the release rate limit, sr curing these
fans is not a certainty, which is inconsistent with the LER statement that cserators "will
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secure main exhaust fans." in addition, since securing the main exhaust fans involves a
manual calculation by the operators to evaluate the release rate, the LER statement
regarding "quickly terminate the event" is questionable. The need to perform the manual
calculation increases the possibility of operator error.
The NRC discussed the concern with the licensee, vihe changed procedure ARP 2590H
(Rev. 2, Change 6) to state that if a loss of coolant.iccident has been diagnosed, stop all
main exhaust fans.
c.
Conclusions
10 CFR 50, Appendix B, Criterion XVI, requires that measures be established to assure
that conditions adverse to quality, such as deficiencies, deviations, and nonconformances
are promptly identified and corrected. The NRC decision to not backfit the licensee to
address the damper AC-11 single failure vulnerability was based heavily on the operator
compensatory action described in LER 50-336/94-40-02 involving securing the main
exhaust fans in response to the Unit 2 stack radiation monitor alarm. The licensee's
corrective actions to address this single failure concern were inadequate in that the Unit 2
stack radiation monitor alarm response procedure failed to ensure the main exhaust fans
were secured and is considered a violation. (Violation 336/97-02-13)
E8.3 (Closed) Unresolved item 50-336/95-27-01: Review of Reload Safety
Analvsis Recort
a.
inspection Scone
The inspectors reviewed the corrective actions implemented in r'sponse to the subject
unresolved item.
b.
Observations and Findinas
This item concerned a weakness that was identified for Cycle 10,11,12, and the current
Cycle 13 Reload Safety Analysis Report at Millstone 2. The licensee apparently had no
records which documented that the reload safety analysis reports had been reviewed.
Paragraph 6.2.2 of NGP 5.05 procedure notes that "the result of the independent review
shall be documented on the Design Review Form (Figure 7.4) by the independent
reviewer ".
.
The inspector reviewed Nuclear Group Procedure, NGP 5.05, " Design input, Design
Verification, and Design Interface Reviews" and NGP 6.06, " Processing and Control of
Purchased Material Equipment, Parts, and Services." The inspector also reviewed Nuclear
Engineering Procedure, NFE 4, " Purchase of Analysis on a Sole Source Basis" step 6.4.9 to
ensure all deliverables were received, and to provide reasonable assurance that the
engineering service was accurate and free of enorc. Furthermore, the inspector reviewed a
sample of Fig. 7.4 Form " Review of Analysis Deliverable" and found it to be technically
accurate, and in compliance with NFE procedures.
c.
Conclusions
The licensee's actions taken to address this unresolved item were acceptable. This item is
closed.
E8.4 (Closed) URI 50-336/95-81-01 and (Open) eel 50-336/96-201-29: Trendina and
Prioritization of Non-Conformance Reports (NCRs)
a.
Insoection Scone (92903)
The inspectors reviewed the corrective actions implemented in response to the subject
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unresolved item (URI) and escalated enforcement item (EEI).
b.
Observations and Findinas
The licensee's quality assurance program requires that a trend analysis of non-
conformances documenting program / procedural problems be performed, and the trend
analysis reports identifying program /procedursi problems be periodically reported to upper
management by the organization responsible for controlling the problem report document.
URI 50-336/95-81-01 concerned the fact that non-conformance reports (NCRs) initiated by
the QA Department and Level "D" adverse condition reports (ACRs) were not included in
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the trend report nor was there any requirement to trend these items. Based on this finding,
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the lack of trending of NCRs and verifying the effectiveness, and adequacy of the ACR
database by the Quality Assurance Department was considered an unresolved item.
In a related finding, eel 50-336/96-201-29, identified inadequate corre<#ive actions
concerning the resolution of existing NCRs. Many NCRs had remained op3n for years
without any corrective actions being performed,or, if performed, the NCR 'was not
adequately closed out. The lack of trending noted above and inadequa e corrective actions
to audits apparently helped lead to this problem. The,aspector reviewed a listing in which
all outstanding Unit 2 NCRs have been identified and assigned responsible engineers for
closure.
The licensee has established procedure OAS 2.14, " Trend Review of Non-conformance
Reports," which requires trending of NCR backlogs and adverse trend areas. The inspector
verified that such trend reports have now been issued, in addition, QA has performed
several audits of the NCR and ACR (CR) pre:ess. Procedure RP4, " Corrective Actions
Program," has been issued to more formalize the corrective actions process. Each unit has
established a corrective actions group to resolve ACRs and other corrective action issues
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and backlogs, in addition to the NCR trend report, as required by RP4, each unit issues a
quarterly " Corrective Action Trend Report." The inspector observed that QA has
established a program to periodically audit the corrective action program and to perform
periodic surveillances of the implementation of licensee corrective actions, and that such
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audits and surveillances are being conducted.
The licensee issued a memorandum on August 15,1996, titled " Interim Guidance on
Operability /Reportability Reviews of NCRs." This memorandum requires that an ACR (now
called a CR) be generated in tandem with the NCR to provide the operability /reportability
review by the shift rnanager. The only exception is NCRs generated by the receipt
inspection process. The memorandum further stated that appropriate procedures were to
be revised to reflect the requirements of the memorandum. The inspector noted that
neither procedure RP4 nor the NCR procedure, NGP 3.05, have been revised to reflect the
NCR-CR tie in. During t, licensee review of corrective actions to resolve this EEi, the
licensee observed that procedures had not yet been updated to reflect the memorandum.
On March 24,1997, Condition Report M2-97-0466 was issued to identify the fact that
procedures had not yet been revised.
c.
Conclusions
Based on the above review, licensee corrective actions associated with URI 50-336/95-01-
01 were found acceptable and this item is considered closed. However, eel 50-336/96-
201-29 remains open because procedure RP-4 has not yet been changed to proceduralize
the practice documented in the August 15,1996, memorandum regarding generating an
ACR as a means of tracking NCRs.
E8.5 (Closed) Follow-un Item 50-236/95-201-07: Control of Molded Case Circuit Breaker
Adiustable instantaneous Trio Settinas
 
a.
Insoection Scone
The inspectors reviewed the corrective actions implemented in response to the subject
follow up item.
b.
Observations and Findinas
During the 1995 Restart Assessment Team inspection of Millstone Unit 2, the team
observed the testing of two molded case circuit breakers. The testing was observed to be
satisfactory except that there was no documentation of the trip settings for the breakers.
Breakers were routinely left at their high trip settings. This appeared to have the potential
for causing spurious tripping of safety related equipment, in a July 31,1996, response to
a letter from the NRC dated May 3,1996, the licensee stated that adjustable instantaneous
trip settings will be incorporated into a controlled plant procedure.
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The inspector verified that the licenseo issued site common maintenance procedure C MP
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751 A, " Molded Case Circuit Breaker inspection and Testing." This procedure superseded
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Unit 2 specific procedure PT21421D. Essentially this procedure specifies that breaker
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setting shall be left in its "as is" position for already installed breakers. Breaker settings for
newly installed breakers shall be per engineering instruction.
Licensee engineering identified all adjustable molded case circuit breakers, and determined
that all but one would be set at the high setting. This was done by a memorandum dated
June 8,1995. Hence, the high setting observed by the inspection team was the correct
setting for the breakers being tested. The inspector observed that engineering drawings
have been revised to specify adjustable breaker settings. With the exception of one
breaker set on low all other breakers are set on the high setting.
c.
Conclusions
Licensee corrective actions to address this follow-up item were acceptable. This item is
closed.
E8.6 (Closed) Unresolved item 50-336/96-05-11 (IFS No. 96-05-17); Failure to Update
the FSAR in a Timelv Manner as Reauired by 10 CFR 50.71(e) (SIL 38 CLOSED)
a.
Inspection Scone
The intpectors reviewed the corrective actions implemented in response to the subject
unresolved item.
b.
Observations and Findinas
This unresolved item noted that some detailed information relative to the cooling capability
of the spent fuel pool was provided to the NRC by the licensee in support of Technical
Specification (TS) Amendment No.114 but was not included in subsequent updates to the
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FSAR. The supporting safety evaluation to the TS amendment stated that the spent fuel
pool cooling system may not be capable of removing the decay heat required to maintain
the SFP temperature below 140 degrees Fahrenheit during the first 21 days of a core
offload. This determination assumed a nominal one-third core offload and a single failure in
the cooling system. The amendment modified the TS to require a minimum decay time of
504 hours (21) days for a one-third core offload. 10 CFR 50.71(e) requires that FSAR
updates must be filcd annually or 6 months after each refueling outage provided the
interval between successiv9 updates does not exceed 24 months. Amendment 114 was
issued on November 14,1986, and as of the dates of inspection 50-336/96-05, the FSAR
had not been revised to reflect the SFP cooling capability as discussed above.
The absence of information in the current FSAR was considered a potential violation of 10
CFR 50.71(e). The item was called unresolved pending a more broader collective review
FSAR discrepancies. The inspector verified that the FSAR has now been revised to reflect
SFP capability, and the specific technical issue has been resolved.
The unresolved item is nM cited because it is an isolated example of a much broader issue
for wh. 5 potential esc';ated enforce actions have been issued concerning plant operation
that has tu. -sistent with the licensing basis. The licensee is currently addressing
these issues through its configuration management program. In addition there is an
 
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independent Corrective Acho Program (ICAVP) by the licensee to verify their licensing
basis; and, there will be su aquent NRC verification of the ICAVP process.
The inspector reviewed the following licensee procedures:
:
(1)
NGP 4.02, " Proposed Technical Specification Change Requests and Proposed
;
Technical Requirements Manual Changes," Revision 10, January 8,1997
(2)
Design Control Manual (DCM), Revision 5, April 16,1997
(3)
NGP 4.03, " Changes and Revisions to Final Safety Analysis Reports,"
Revision 9, April 8,1997
NGP 4.02 requires that the originator of a TS change determine if information in the FSAR
will require a change or updating, if the proposed TS change request is approved, and if
the NRC approves the amendment to the TS. If the FSAR will be affected, an FSAR
change request should be initiated. NGP 4.02 also provides a mechanism for processing
the proposed FSAR change request, if a design change is made, the DCM provides a
mechanism for reviewing the design change for potential FSAR changes. In addition to
- procedural requirements, DCM Form 3-28, Design Change Administrative Checklist
provides a mechanism for documenting a proposed FSAR change request, if required by
the design change. NGP 4.03 provides the mechanism for actually updating the FSAR.
Following the requirements of these procedures should assure that any current TS or
design changes are incorporated into periodic FSAR updates when required,
c.
Conclusions
Based on the above licensee actions already in progress concerning configuration
management, required independent reviews to follow, and subsequent planned NRC
inspection activity; and because the FSAR has been revised to reflect the correction of the
specific item identified above, this unresolved item is closed.
E8.7 (Ocen) Escalated Enforcement item 50-336/96-09-10: Erneraency Diesel Generator
Corrective Actions (SIL 26 UPDATE)
a.
Inspection Scope (92903)
The inspectors reviewed the licensee actions that were taken following an emergency
diesel generator (EDG) bearing failure in March 1996 for which the licensee failed to
identify the root cause and implement corrective actions,
b.
Observations and Findinas
Subsequent to the EDG bearing failure in March 1996, a catastrophic failure of the "B"
EDG engine occurred. The engine failure resulted in an extensive review by an Event
Review Team (ERT) which identified numerous contributing causes to the failure, and
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provided a comprehensive cortactive action plan.
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The failure of the licensee to identify the root cause of the March 1996 bearing failure and
implement appropriate corrective actions was one of numerous examples of inadequate
corrective action cited by the NRC in that time frame. As discussed in NRC Inspection
Report 96-04, issued June 6,1996, the overall corrective action program was not effective
in correcting identified deficiencies.
- The inspector noted that in addition to the specific corrective actions that were
implemented as a result of the engine failure, the licensee has taken actions to improve the
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corrective action program. This included a revision of procedure RP-4, " Corrective Action
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Program," in February 1997, The licensee provided Condition Report M2-97-0363 and the
initial root cause investigation as an example of improvements in the corrective action
process. The CR documents a problem where an EDG was aligned for automatic starting
following maintenance work but prior to filling and venting the lube oil system. An-
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The condition was documented and a root cause investigation was performed even though
automatic start could have resulted in engine damage as a result of inadequate lubrication.
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no automatic start or engine damage occurred.
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c.
Conclusions
 
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- This item remains open pending the completion of NRC considerations of escalated
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enforcement action for this issue. The overall effectiveness of the corrective action
program is being tracked in the NRC Restart Assessment Plan as Significant Issues List
Item Number 5.
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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 continued its implementation of the Millstone Unit 3 Recovery Plan and the
configuration management program activities in support of the milestones leading to the
readiness for the unit restart.
On May 5,1997, the licensee announced that Unit 3 was designated as the lead unit and
would be the first unit ready for external review under the provisions of the Independent
Corrective Action Verification Program (ICAVP). In addition, the licensee decided that the
recovery managers for Unit's 1 and 2 would assist Unit 3 in its recovery process. Mr. J. P.
McElwain, in addition to continuing as the Unit 1 Recovery Officer, assumed responsibility
at Unit 3 in the area of physical plant readiness; and Mr. M. Bowling, the Unit 2 Recovery
Officer, was assigned additional responsibility for Unit 3 regulatory readiness. Both
individuals report to Mr. M. Brothers, the Unit 3 Vice President and Recovery Officer.
On May 19,1997, Mr. M. Brothers declared Unit 3 ready for commencement of the
ICAVP. Mr. M. Bowling concurred with this decision after the conduct of an independent
contractor review of Unit 3 readiness. As of the end of this inspection period, the
Millstone Recovery Oversight group was continuing its review of Unit 3 readiness,
representing the last concurrence required for the recommendation to the executive level
for the ICAVP activities to commence. The Unit 3 " target" date for declaration of ICAVP
readiness to the NRC is May 27,1997.
U3.1 Operations
U3 01
Conduct of Operations
01.1 Operational Observations and Issue Followuo (71707,92901)
Using Inspection Procedures 71707 and 92901, the inspectors conducted frequent reviews
of ongoing plant operations, to include plant inspection-tours, control room observations,
and witness of licensee planned or exigent meetings and briefings. Where appropriate,
interviews were conducted with licensed operators and other support personnel to assess
the level of control and detail of knowledge being implemented with regard to observed
operational evolutions. During this inspection period, in addition to the routine tours and
observations, the following activities were specifically examined, either in progress, or to
address questions bearing on the final disposition of identified problem areas:
mispositioned chlorination throttle valves in the service water system;
a
reference condition reports CR M3-97-0717 & 0731
The inspectoi interviewed workers, examined the subject valves, and
reviewed and discussed w;th the licensee CR investigator the description,
causal factors, and generic implications of this event. Licensee corrective
 
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measures were determined to be commensurate with the signibcance of the
 
,
identified problem.
conduct of emergency core cooling system pump performance testing as an
)
*
Infrequently Performed Test or Evolution (IPTE); reference IPTE procedures
{
IST 3-97-001 & 002
;
The inspector reviewed the safety evaluation for the conduct of both IPTEs,
evaluating the use of dedicated operators during test performance. The
inspector also witnessed a portion of the charging pump testing (IST 3-07-
)
001) and noted that the Shift Manager terminated the conduct of the IPTE
q
activities on two occasions when a potential technical specification (TS)
violation was perceived (CR M3-97-0908) and when a procedure problem
was ideniified (CR M3-97-0924). The inspector reviewed the reportability
evaluation tcr CR M3-97-0908 and concluded that Shift Manager had
correctly and conservatively suspended testing, even though the subsequent
assessment determined that no actual violation of TS had occurred. In both
cases, operator actions were deemed to have been prudant.
charging pump cavitation during valve operability testing; reference CR Mb
*
97-0934
i
The inspector reviewed the surveillance procedure SP 3604A 5 and re;ated
emergency and abnormal operating procedures. License operators on shift
were interviewed and the inspector verified that the affected pump was
,
maintained in an operable status during the conduct of testing and as a result
of subsequent evaluation of the CR. Inspector questions regarding design
flow requirements were clarified by cognizant engineering personnel. The
shift manager took appropriate cautionary actions to ensure pump flows did
not approach observed cavitation limits during continued performance
testing.
 
"
control of locked closed manual containment isolation valves in the bypass
*
lines for the turbine driven auxiliary feedwater (TDAFW) steam supply lines;
reference Northeast Nuclear Energy Company letter B16364
The inspector discussed the purpose of these steam supply bypass lines with
a technical support engineer and confirrned that they had not been
inappropriately used for pre-warming the TDAFW pump prior to the TS
required, time response testing and quarterly pump performance surveillance
activities. The inspector examined the existing field piping configuration and
valve conditions during an inspection tour in the engineered safety features
(ESF) building. Licensee commitments, as documented in licensee event
report (LER) 97-013 and relating to the revision of design and licensing
information on the subject bypass lines and valves, will be reviewed during a
future inspection in followup to the LER.
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loss of "A" train ESF building ventilation as a result of unscheduled work on
*
"B" train equipment; reference CR M3-97-1385
The inspector verified that the licensee entered the appropriate TS limiting
condition for operation, governing residual heat rernoval system operability,
based upon the degradation to the supporting ventilation system. Unit 3
management ordered a stop work to the release of new safety-related,
scheduled work until an event review team assessed the identified concerns
and recommended corrective measures. The inspector observed an event
review team meeting on this s*.(ect and reviewed the Unit 3 Director
decision to allow for a work restart. The conditions placed on the new work
controle appeared to address the causal factors associated with this event.
Work D
had already been released to the field under conditions similar to
the unschaduled ventilation work were subjected to further shutdown risk
and safety impact. Significant licensee management attention was devoted
to this event and its acceptable resolution.
Overall, as determined by NRC followup to the issues and events identified above, the
inspector concluded that the licensee demonstrated an acceptable approach to the control
of planned operational evolutions and good response to problems that developed during the-
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progress of those evolutions. Event review and investigation appeared thorough and
corrective measures appeared well directed. The inspector noted that the effectiveness of
the corrective actions to preclude similar problematic events can only be demonstrated
over time. Nevertheless, the licensee's short-term response and directed additional
controls provided evidence of proper Unit 3 management attention to emergent operational
areas of concern.
01.2 Ooerational Followuo of Safetv Grade Cold Shutdown Controls
a.
Inspection Scope (71707,92700)
The Millstone Unit 3 Final Safety Analysis Report in section 5.4.7.2.3.5 delineates the
requirements for bringing the reactor to a cold shutdown condition under specified criteria
and assumptions. These design-basis critoria, termed " safety grade cold shutdown"
(SGCS) controls, have a regulatory r.exus to the guidance provided in USNRC Regulatory
Guide 1.139. Previous NRC inspect'ons have reviewed the operational control of SGCS
equipment, resulting in the documentation of some unresolved items, one of which (URI
423/96-01-07) remains open. During this inspection, a further review of SGCS controls
was conducted by conducting a followup of condition report CR M3-97-0835, which
described a potential design deficiency with the accident analysis involving certain SGCS
equipment.
b.
Observations and Findinas
The SGCS components discussed in CR M3-97-0835 are the four main steam pressure
relieving bypass valves,3 MSS *MOV74A,B,C,& D. The condition being reviewed was the
postulation that one of these main steam pressure relieving bypass valves being out of
I
service would violate the design basis of the Millstone Unit 3 steam generator tube rupture
 
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..
 
(SGTR) analysis. Further engineering evaluation of this design concern and the licensee's
analysis of the SGTR accident response is discussed in section U3.E2.1 of this inspection
report.
The inspector reviewed the licensee's original reportability determination for CR M3-97-
0835. The licensee had conducted a search of the inservice test records for the subject
main steam pressure relieving bypass valves, had found none of the 3 MSS *MOV74 valves
inoperable with the plant in mode 1, and had concluded that the plant had not been
operated outside its design basis. Therefore, the licensee determined that the event
considered in conjunction with CR M3-97-0835 was not reportable in accordance with the
criteria of 10 CFR 50.73.
The inspector indicated to the licensee, however, that in 1996 two block valves
(3 MSS *MOV 18A&B) upstream of valves 3 MSS *MOV74A&B had been de-energized
closed with the plant in mode 1 (reference: NRC inspection report IR 423/96-01). The
block valve closure had been effected to support maintenance on two atmospheric steam
relief valves, located downstream of the block valves and in a parabel flow path to the
main steam pressure relieving bypass valves. This configuration had not been evaluated in
the licensee's original reportability determination.
After discussions with the inspector, the licensee conducted another reportability
evaluation (M3-97-0835 R1), also considering another adverse condition report, ACR 935,
associated with the potential inoperability of the 3 MSS *MOV18 block valves. The licensee
concluded that local manual action to mitigate a SGTR event with the block valves closed
would not be feasible, and therefore that the conditions evaluated were reportable in
accordance with 10 CFR 50.73(a)(2)(ii)(B). The inspector reviewed the revised
reportability determination, noting that the licensee production maintenance management
system (PMMS) records had not indicated the 3 MSS *MOV18A&B valves to be inoperable
during the time period covered by IR 423/96-01.
The licensee in following up URI 423/96-01-07, had recognized a programmatic weakness
in the plant SGCS controls, and currently has a proposed technical specification change
request (PTSCR 3-25-97) being processed to address the concern over the need for more
rigorous control of the main steam pressure relief bypass valves. The problems
documented above, regarding both the lack of PMMS records indicating accurate block
valve positioning and the noted impact upon accident analysis and 10 CFR 50.73
reportability, further highlight the need for additional licensee control in this area,
c.
Conclusion
Licensee review of all the events related to CR M3-97-0835 has resulted in the
determination that the identified condition is reportable to the NRC in accordance with 10
CFR 50.73. The NRC will conduct further inspection of this issue after the licensee event
report is submitted. Furthermore, URI 423/96-01-07 remains open pending review of the
PTSCR and the licensee's implementation of corrective actions, specifically with additional
focus on the facts developed during this inspectio._.
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U3 07
Quality Assurance in Operations (40500) (SIL 37 & 41 UPDATE)
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07.1 Operational Oversiaht Activities
The inspector met with several Nuclear Safety & Oversight (NS&O) personnel ta discuss
activities and initiatives in the areas of corrective action program enhancement, self
l
assessments, priorities for unit restart readiness,10 CFR 50.54(f) involvement, and
'
conduct of the Nuclear Safety Assessment Board (NSAB) meetings. The inspector n.oted
that the licensee met its established milestone to implement a new corrective action
program (RP-4) by March 31,1997. Evaluations are continuing for proper implementation
of this program and assessing its effectiveness over the next several months. Additionally,
the Inensee has hired a contractor with industry-wide corrective action program experience
to assess the quality of root cause analyses and the resultant reports and corrective ur: tion
conclusions.
,
The inspector also noted that the licensee has implemented a self-assessment program
improvement plan, including efforts involving process and procedural revisions, training
initiatives, implementation and monitoring activities, and the confirmation of results, lo
developing this improvement plan, the licensee has " benchmarked" similar programs at
other nuclear plants where the licensee's self assessment ir,;tiatives have-been deemed
effective.
In monthly meetings with NS&O performance evaluation personnel, progress on the
Nuclear Oversight Recovery Plan, assessment of the unit readiness to restart, and strategic
planning priorities were discussed. Performance evaluation participation in daily plant
meetings and event review team efforts, as well as in the conduct of surveillances directed
to perceived plant or ppgrammatic problem areas, have been noted.
Finally, the inspectors have been kept informed, through status reports and periodic
meetings, of the progress made by the Recovery Oversight organization in its assessment
of ongoing configuration management program work. During an NSAB meeting attended
by an NRC branch chief, differences between Recovery Oversight er.d line management n
the expectations for measuring progress of the 10 CFR 50.54(f) project were discussed.
This resulted in a subsequent meeting chaired by the Senior Vice President and Chief
Nuclear Officer to establish a common set of goals. The results of these licensee
deliberations on goals and expectations have been discussed in terms of a Recovery
Oversight " gap analysis" at public meetings conducted by the NRC.
Overall, as discussed above, while the licensee NS&O organization continues implementing
initiatives and efforts directed toward program improvements and enhancement, the final
NRC measure of NS&O success will be the effectiveness of its relationship with the line
organization in the unit recovery and proper plant operation thereafter. Progress toward
'his goal will continue to be monitored during future NRC inspections, and will be tracked
as appropriate, with respect to SIL items 37 and 41.
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U.S. Nucirr R:gulatory Commission
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B16619\\ Attachment 1\\Page 1 Millstone Unit Nos.1,2, and 3 Facility Operating License Nos. DPR 21, DPR-65, NFP-49
U3 08
Miscellaneous Operations issues (92700)
0.8.1 Technical Specification (TS) Noncompliance
a.
Scope
Several licensee event reports (LERs) recently issued have dealt with TS noncompliance
issues. The inspector reviewed the LERs for root cause and safety significance
determinations, and adequacy of corrective actions. The inspector also verified that the
reporting requirements of 10 CFR 50.73 had been met.
b.
Observations and Findinas
(Closed) LER 97-08: (SIL 5 UPDATE):
In accordance with TS 3.6.3 and 3.7.1.5, main steam isolation valves (MSIVs) are required
to be operable during Modes 3 and 4. However, below 350oF, the MSIVs are technically
inoperable because they cannot meet the required closure times. During a plant shutdown
and cool down conducted on April 15,1995, the MSIVs had been shut per operating
procedure. On April 16 adverse condition report (ACR) 01844 was written stating that a
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TS limiting condition for operation should have been entered per TS 3.03. An evaluation of
the ACR at that time determined that the TS had been met since all four MSIVs were
already shut and that the event was not reportable per 10 CFR 50.73. As a result of the
ACR, operating procedures were changed to assure that MSIVs would be shut prior to
going below 350 F. A TS change was submitted to the NRC on June 20,1995, to clarify
TS 3.6.3 and 3.7.1.5. This change has not yet been approved by the NRC.
On reviewing the status of the TS change request submitted in June 1995 the licensee, on
January 16,1997, reviewed the corrective actions for ACR 01844 and determined that
there had been a TS violation and it should have been reported to the NRC per 10 CFR
50.73. Based on this licensee determination, ACR M3-97-0170 was written and LER 97-
08 was submitted to report the April 1995, TS violation. The violation was of low safety
significance since the MSIVs had already been shut and the licensee was proceeding to
cold shutdown for a refueling outage.
The corrective action plan for ACR M3-97-0170 requires the implementation of the new
requested TS 3.7.1.5 and 3.6.3. The inspector verified that the licensee's current
checklist for entering Mode 4 from their current Mode 5 requires that the TS amendment
be approved.
LClosed) LER 50-423/97-06-01: This LER documents that the residual heat removal
suction containment isolation valves had not been maintained closed in mode 4 as required
by TS 4.6.1.1.a. Technical specifications requires that all penetrations not capable of
being closed by containment automatic isolation valves or operator action during periods
when containment isolation valves are under administrative control be secured in their
accident position. The subject valves had been opened in mode 4 in accordance with unit
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operating procedures to provide a flow path for plant cool down to cold shutdown as
 
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Reply to a Notice of Violation Restatement of Violation Title 10, Code of Federal Regulations, Part 20.1101 (10 CFR 20.1101) requires, in
.
 
required by plant design. There was no specified administrative controls (operator action)
in place to control these valves.
,
As corrective action, the licensee performed a review to verify that those manual
containment isolation valves that potentially require intermittent operation in modes 1
through 4 were included in TS 4.1.1.a. The review identified four additional valves that
are operated in modes 1 through 4 that were not included in the TS. These valves are
normally opened to allow the performance of surveillance tests. The inspector verified that
the licensee reviewed manual containment isolation valves that require intermittent
;
operation in modes 1 through 4 and developed a proposed TS change request to include
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the valves in TS.
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c.
Conclusion
The two LERs discuss conditions prohibiter] by TS. Further NRC review of each LER
established that while the licensee's or, err.tional activities were proper evolutions, literal
compliance with the plant TS had not Leen maintained. Based on the above corrective
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actions and the low safety significance of the issue, these licensee-identified and corrected
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minor violations are being treated as Non-Cited Violations, consistent with Section IV of
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- the NRC Enforcement Policv. The listed LERs are closed. SIL ltem No. 5 is partially
.
r:losed.
However, the closure of the LERs does not address the generic concern for TS compliance.
A review of LERs issued since April 1996 revealed that there have been a number of LER's
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that have dealt with TS compliance problems relating to questionable interpretations This
part, that licensees develop and implement a radiation protection program. Paragraph 1.1 of procedure RPM 5.2.2, " Basic Radiation Worker Responsibilities," r0 quires, in part, that workers entering the radiologically controlled areas (RCAs) con; ply with instructions provided by the radiation protection staff, including those instructions contained in radiation work permits (RWPs). All entries to the RCA require that station radiation workers be signed in on a general or specific radiation work permit (RWP)
area is of current interect for further NRC review and is included as an NRC followup
and wear a functioning digital alarming dosimeter and thermoluminescent dosimeter (TLD).
activity, documented as S L ltem 70.
)
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O.8.2 (Closed) LER 50-423/97-09: documents a historical event where a high energy line
break (HELB) door was open in violation of the HELB design criteria. The licensee
considered this event to be the result of their failure to develop and implement an effective
HELB program. This issue was previously discussed in NRC Inspection Report 423/97-01.
No further NRC inspection followup is deemed necessary; consequently, LER 97-09 is
closed,
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U3.Il Maintenance
U3 M1
Conduct of Maintenance
M1.1 General Comments
a.
Inspection Scooe (62707)
The inspector observed / reviewed all or portions of the following maintenance activities:
i
M3-97-06401,
install restricting orifice 3SlH*RO40
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M3-97-06471,
install freeze seal for isolation of restricting orifice 3SlH*RO40
e
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_
i Contrary to the above, five instances of personnel entering the RCA without weanng a functional electronic dosimeter or TLD were identified. These include orso '.1 stance in i
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Unit 1 on April 15,1997; three instances in Unit 2, one each on March 5,1997, March j
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7,1997, and April 15,1997; and one instance in Unit 3 on April 29,1997.
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l This is a Severity Level IV violation (Supplement IV) for Docket Nos. 50-245, 50-336, and 50-423.
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b.
Observations and Findinas
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The inspector noted that fire watches were established for the welding activities and
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personnel were monitoring the freeze seal temperature as required by maintenance
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procedure MP 3709C. Contingency actions for the potential loss of a freeze seal had been
developed as part of the safety evaluation for the modification. Discussions with the Shift
Manager revealed that control room operators were aware of the required contingency
actions in the event of seal failure. However, the contingency actions did not address all
areas covered in procedure MP 3709C. With respect to the maintenance procedure,
requiring that a Plant Operations Review Committee (PORC) approved contingency plan be
developed and maintained on file in the control room, the licensee opted for less formal,
verbal contingency planning. A condition report was generated to document this concern.
i
The inspector also reviewed the work activities and verified proper isolation and retest
requirements were identified. Although not specifically listed on work order M3-97-06401
or the ASME section XI repair and replacement plan for the installation of the restricting
orifice, the design change request correctly identified the need for a flow balancing test.
i
This test is required by Technical Specifications 4.5.2.h following completion of
i
modifications to the emergency core cooling system subsystem that alter the subsystem
flow characteristics.
c.
Conclusions
The inspector concluded that the tagging boundary and retest requirements for the work
activities were adequate. Although a PORC approved contingency plan was not un file in
the control room, the Shift Manager and the control room operators were aware of the
required actions in the event of a freeze seal failure.
The inspectors determined that the maintenance and surveillance activities observed were
i
properly performed and a CR was initiated to document the concern regarding contingency
planning.
U3 M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Maintenance and Confiauration Control of Pipe Suncorts
a.
Inspection Scoce (62703,37551)
During the conduct of field inspection-tours, the inspector selected three types of
leedwater system (FWS) pipe support / whip restraint assemblies for detailed review. The
material condition of a sample of the support types, including snubbers, was examined;
component identification markings were noted; and the field configuration of each general
support type was evaluated against its respective design drawing and specification
requirements. The inspector selected welding, bolting, location, attachrnents, and base
plates and anchorages as the criteria for specific review. Where certain drawing
discrepancies were identified, the inspector assessed the licensee's follow-up and
i
corrective actions.
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=
Reason For The Violation Northeast Nuclear Energy Company (NNECO) agrees with the cited violation. This violation was caused by inadequate human performance and was a repeat of the same type of problems identified by Notice of Violation 50-336/97-01-09.
.


b
Corrective Steps Taken and Results Achieved A Condition Report (CR), " Adverse Trends in Personnel Performance," was written on May 6,1997, to identify common / root causes and recommend corrective actiona with regards to adverse trends in personnel performance. The adverse trends in human performance were seen in Health Physics issues (lack of proper dosimetry).
Observations and Findinas
The inspection of a support restraint assembly (3-FWS-4-PSR-050) and snubber /suppressor
configurations (3-FWS-PSSP-25 & 26) identified no hardware deficiencies or deviations
from the original design details, augmented by the applicable Engineering & Design
Coordination Reports (E&DCRs). The inspector examined the Stone & Webster (S&W)
design drawings and spot-cneckeo the fabrication and field installation specifications for
consistency with the as-built assemblies. Acceptable material conditions and a proper field
configuration were noted for these sample support types.
On the third type of support, pipe rupture whip restraints (3-FWS-PfiR6 & 7, North &
,
South), the field inspection revealed some apparent design discrep&cies, as follows:
S&W Specification 2280.000-940 and drawing EV-56E-4 both delineate specific
*
details for shimming the gap (a clearance of approximately 1/16") between the whip
restraint structural beams and the concrete wall embedments after the conduct of
'
hot functional testing, to allow for the unrestrained thermal growth of the main
structural members. The inspector noted that no shims had been installed on the
beam-to-wall connections. A design change record review revealed that while
E&DCR T-J-03934 addressed changes to the end connection / shim details, it did not
<
authorize elimination of the shims or modify the specification requirements for
restraint beam-to-wall clearance dimensions.
A subsequent desigr..odification, installed in 1989, implemented a welded
*
attachment of nonsafety-related electrical conduit supports to the main structural
support beam of whip restraint 3-FWS-PRR6N. The plant design change record,
PDCR MP3-89-002, for this modification documents in the 10CFR50.59 Safety
Evaluation that conduit and support installations will be performed in accordance
with S&W Specification SP-EE-076; also indicating that no seismic ll over i
condition is created by this design change. However, no evidence of engineering
approval for the conduit support attachment, as required by SP-EE-076, was
retrievable. Furthermore, field inspection revealed safety-related components in
proximity to the nonsafety conduits, indicating that a seismic 11 over i evaluation
should have been performed.
Subsequent tn the identification of these discrepancies, the licensee initiated condiden
reports, CR M3-97-1272 for the shim concern and CR M3-97-M61 for the attached
conduit supports. Immediate corrective actions included a review cf pipe whip restraint
calculations and the conduit support details. Th,s licensee concluded that component
operability had not been adversely affected because the subsequent design reviewr
demonstrated that the shims were not functionally required and the subject conduit was, in
retrospect, seismically supported. Additionally, licensee engineers conducted some further
field inspection of another group of pipe whip restraints, as design detailed or; S&W
drawing EV-46K. Based upon a sample of specifi: inspection criteria, no further design
discrepancies were found.
J
Based upon this expanded inspection sample of insaned pipe whip restraints, additional
pipe support inspections implemented in accordance with engineering instruction 3DE-97-


_
A Common Cause Analysis was conducted and the following root causes were identified in the radiation protection program area:
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Root Cause 1 - Inconsistent reinforcement of site performance expectations by managers and supervisors.


003, ongoing configuration management re-evaluations, and prior inspections performed on
Root Cause 2 - Failure of management to effectively establish and communicate a site accountability system.
pipe support assemblies potentially affected by design temperature considerations, the
i
licensee concluded that the discrepancies identified during this NRC inspection were not
representative of generic problems with the as-built pipe supports.
c.
Conclusion
NRC field inspection identified one specific series of pipe whip restraints with the as-built
)
configuration deviating from the existing design details with respect to certain criteria. The
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noted discrepancies were provided further engineering evaluation by the licensee and
determined to not result in adverse impact upon the affected component functionality.
Additional i; cense assessments have concluded that the identified discrepancies are not
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reflective of a more general problem. However, given that the identified deviations
involved elements of questionable control of both a E&DCR and a PDCR, the licensee's
handling of design change documents, at least on this one whip restraint assembly,
represents a concern. Pending both the final closura of CRs M3-97-1272 and M3-97-
1461, along with presentation of further evidence by the licensee that a causal problem
linkage does not exist in the processing of other pipe support design changes, this issue
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remains unresolved. (URI 423/97-02-14)
U3 M7
Quality Assurance in Maintenance Activities
M 7.1 Maintenance Corrective Action /ASME Code Compliance
a.
Inspection Scope (62703,40500)
The inspector reviewed the implementation of corrective maintenance on service water
system relief valve 3SWP*RV96A, as documented in nonconformance report NCR 397-
057. Inspection followup included a field inspection for material condition, ASME code
compliance, and generic corrective actions, The inspector also assessed the licensee's
controls in handling the identification of a concern involving the procurement of service
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water system (SWP) piping fittings and components. Discussions with cognizant licensee
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maintenance and procurement personnel revealed questions regarding the issuance of parts
certified to the American Society of Testing and Materials (ASTM) standards for installation
in the SWP (i.e., an ASME Section Ill) system.
b.
Observations and Findinas
During maintenance on relief valve 3SWP*RV96A, interior pitting was identified on the
valve bonnet and documented on NCR 397-057. Ultrasonic testing (UT) was performed by
the licensee to determine that the minimum valve wall thickness was acceptable and that
no repair was required. However, the NCR incorrectly identified both the pitting and
subsequent UT to apply to the valve body, vice the bonnet. A review of the technical data
sheet for this valve indicated that the body consisted of a copper-nickel baso material,
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while the bonnet was an aluminum-bronze casting.
,
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The inspector questioned this inconsistency since the American National Standard, ANSI
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B16.34-1981, documented in the "use-as-is" disposition of the NCR was found to not have
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.>4p M-We bem.


endorsed the material type (SB148-954) used in the fabrication of the valve bonnet. While
64*we...
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h.
the minimum allowable wall requirements delineated in ANSI B16.34-1981, as referenced
by later ASME Section 111 code editions, were technically adequate, the design specification
!
(2472.110-186) for this relief valve referenced earlier ASME Section ill editions, and a
different standard, i.e., ANSI B16.5. Further, during field inspection of maintenanco work
on the subject relief valve, the inspector noted a missing lock wire on a similar relief valve
(3SWP*RV96B) in the opposite train. Such a condition is contrary to the ASME Section 111
requirements for valve sealing and setpoint adjustments.
,
l
Upon raising these concerns to the responsible licensee personrel, the inspector was
provided a copy of condition report CR M3-97-1006, which had already documented
missing or broken lockwire conditions on several SWP relief valves, including
3SWP*RV968. With regard to the NCR 397-057 discrepancies, the licensee issued a new
NCR 397-095, documenting a new disposition to acceptance of the pitted valve bonnet in
accordance with applicable requirements of ANSI B16.5, with reference to the 1971
edition of the ASME section ill code and an applicable Code Case 1288. These documents
were verified by the inspector to establish the governing endorsements for use of SB148
aluminum-bronze cast materialin the relief valve bonnet construction.
~ln a related question on ASME Code Case usage, the inspector was informed that small
,
piping parts and fitting material had been procured to ASTM requirements from a non-
ASME supplier and issued for installation in the SWP system. Such material usage was
believed to be authorized by the intent of ASME Code Case N483; subsequently
determined in review by the NRC inspector and licensee procurement engineers to
represent a code case that has not been endorsed by USNRC regulatory guidance.
Upon discovery that the affected SWP items had been ordered, received, and issued to the
field with questionable certification to the intended ASME applications, the licensee
removed the subject material from inventory and placed it in a " hold" status. CR M3-97-
1089 was issued to document this problem and follow up and track the potential
nonconforming condition of improperly certified material being issued and installed in the
safety-related sections of the SWP system. The inspector reviewed CR M3-97-1089 and
discussed continued evaluation of this problem with cognizant licensee engineering
personnel.
c.
Conclusions
The inspector identified a field concern and a discrepancy in the NCR disposition to a
questionable ASME relief valve material condition. Licensee corrective maintenance was
already in progress and a new NCR was issued to clarify the governing ASME/ ANSI
requirements for acceptance of the installed valve. The inspector noted that an existing
CR, M3-97-1006, had been issued to correct the missing relief valve lock wires. Also, the
licensee issued another CR, M3 97-1089, to follow up and correct any unauthorized non-
ASME material issued for usage in the SWP system. The inspector determined that
licensee corrective actions to address these issues have been appropriate and intends to
review the final resolution of CRs M3-97-1006 & 1089, tracking their closure as an
inspector followup item. (IFl 423/97-02-15)
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U3 M8
~
Miscellaneous Maintenance lasues
E~.
M8.1 (Closed) LER 97-002-00: Torquing of Battery Connections Not Performed
a.
Insoection Scope (92903)
The inspectors reviewed the licensee findings and corrective actions taken regarding the
failure to check the tightness of the battery connections during surveillance testing.
b.
Observations and Findinos
Technical specification surveillance requirement 4.8.2.1.c.2 requires that the licensee
verify that "The cell-to-cell and terminal connections are clean, tight, and coated with
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anticorrosion material." The licensee previously had considered the resistance check of the
, ~ ~ ~
cell-to-cell and terminal connections to be adequate to ensure connection tightness. A
-,' n
recent review by the licensee identified that the technical specification bases reference
~ ~ ~
IEEE Standard 450-1980, " Recommended Practice for Maintenance, Testing, and
' ~ ~
Replacement of Large Lead Storage Batteries for Generating Stations and Substations."
This standard recommends a check of the tightness of connections of bolted connections
to the torque requirements of the battery manufacturer. A check of connection torque-
-
values was not being performed as part of the battery surveillance test program.
Although the torque values were not being checked in the past, resistance checks and
battery discharge tests had been performed as required, with satisfactory results.
The licensee revised surveillance test SP3712NA, " Battery Surveillance Testing," to include
the check of bolted connection tightness and performed the procedure to ensure the
correct torquing.
The inspector confirmed that the procedure had been revised as stated in the LER.
c.
Conclusions
The inspector concluded that the licensee had appropriately addressed this issue. This
licensee-identified and corrected minor violation is being treated as a Non-Cited Violation,
consistent with Section IV of the NRC Enforcement Poliev. LER 97-002-00 is closed.
M8.2 (Closed) LER 97-005-00: Circuit Breaker Testing With Gages Not in Measuring and
Test Equipment (MT&E) Program
a.
Inspection Scoce (92903)
The inspectors reviewed the licensee findings and corrective actions taken regarding the
use of tools that were not controlled within the MT&E Program.
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b.
Observations and Findinas
in January 1997 the licensee identified that gages used during circuit breaker maintenance
to check dimensions of clearances were not controlled within the site MT&E Program. One
of the gages used to perform maintenance on the 4160 Volt circuit breakers was found to
be out of tolerance. The affected circuit breakers were declared inoperable until the
preventive maintenance (PM) procedures were performed using a qualified gage. When the
preventive maintenance was performed, all measurements were found to be acceptable.
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Additional actions included a review of other tools and procedures to determine if similar
I
conditions existed. Two other tools were thus identified; but when checked, were found
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to be with tolerance.
c.
Conclusions
The inspector concluded that the licensee had appropriately addressed this issue. LER 97-
005-00 is closed,
i
M8.3 LQlosed) ACR M3-96-0557 (Partial - SIL ltem 58);
Safety injection System
Hydrosatic Test
(Closed) LER 96-032-00 (Partial - SIL ltem 81);
(Undate) eel 96-201-33 (Partial - Sil item 58);
a.
Insoection Scope (92903)
l
The inspectors reviewed the licensee findings and corrective actions taken regarding the
adequacy of the high pressure safety injection system hydrostatic test.
l
b.
Observations and Findinas
Adverse Condition Report (ACR) M3-96-0557 and Licensee Event Report (LER) 96-32-00
address an issue where high pressure safety injection piping was not tested in accordance
with ASME code requirements. Following a change in the setpoints for thermal relief
valves and an upgrade in the system design pressure a hydrostatic test was performed at a
l
pressure of 1.1 times the relief setpoint. The correct test pressure should have been 1.25
tirr.es the relief setpoint.
l
The licensee subsequently reperformed the hydrostatic test at the correct pressure and
provided trainina for the individuals responsible for performing hydrostatic testing.
'
c.
Conclusions
The inspector reviewed the work orders and associated documentation for the performance
of the testing at the correct pressure and found that the licensee had properly tested the
system. ACR M3-96-0557 and LER 96-032-00 are considered closed. eel 96-201-33
remains open due to ongoing NRC considerations of potential escalated enforcement action
<
involving this issue.
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M.8.4 (Closed) LER 50-423/97-12: This LER documented that temporarily installed
concrete blocks, serving as the weighted tornado missile restraints for electrical manhole
covers, had been removed for a period of three minutes during a maintenance activity.
This was done to allow removal and reinstallation of sealant on the covers. Personnel
reviewing and performing the maintenance activity failed to identify the bypass-jumper
requiring the blocks or recognize the safety-related function of the concrete blocks until
they had already commenced the work activity. The inspector determined that the
reported concern represented a minor issue and that LER 97-12 is closed.
U3.Ill Enaineerina
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U3 E1
Conduct of Engineering
E.1.1 Deslan Control Weakness
a.
Insoection S,. cone
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Several licensee event reports (LERs) recently issued have dealt with conditions that are
outside the design of the plant. The inspector reviewed the LERs for root cause and safety
significance determinations, and adequacy of corrective actions. The inspector also
verified that the reporting requirements of 10 CFR 50.73 had been met,
b.
Observations and Findinas
(Closed) LER 50-423/96-27: documents that tornado restraints for five safety related
electrical manhole covers were not installed. The manholes contained safety-related
cabling which could be damaged by a missile in the event that a manhole cover was lifted
by the forces that could develo,p during a tornado. There was no evidence that hold-down
restraints for the manhole ccvers were ever installed. As corrective action, the licensee
installed concrete blocks of sufficient mass over the manholes to restore tornado
protection until a permanent design change is implemented. The inspector verified that
blocks were placed over the affected manholes, and that work orders and a design change
were generated to install permanent hold-downs for tornado protection. This condition is
scheduled to be resolved prior to unit restart.
(Closed) LER 50-423/96-41: documents that the gap between the tubes and the lower
tube sheet for the service water (SWP) pump strainers was not in accordance with design
requirements. The tube sheets had been replaced in 1988 due to galvanic corrosion
problems. The tube sheets and filter elements had erroneously been considered to be
nonsafety-related and consequently a nonsafety control process for the manufacture of the
internals was used. This issue was discussed in NRC Inspection Report 423/96-09. The
inspector verified that a temporary modification was performed for each SWP strainer to
restore the designed diametral clearances; and that an evaluation was performed that
concluded the SWP strainer was a safety-related component. A permanent design change
to restore the tube sheets to conform with design requirements is scheduled to be
performed prior to unit restar,
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c.
Conclusio2
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The two LERs discuss conditions where installed equipment or actual plant configuration
!
differed from the Final Safety Analysis Report (FSAR) descriptions. These errors did not
directly impact the safe operation of the plant. The specified design concerns have either
been corrected, or are scheduled to be fixed prior to plant startup. The listed LERs are
closed. However, the closure of the LERs does not address the effectiveness of the design
 
control process at Millstone Station. This area is under current NRC review and is included
as an ICAVP followup activity that is documented as SIL ltem 79.
 
E1.2 inservice insoection (ISI) Proaram Review
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a.
Inspection Scope (73753)
According to 10 CFR 50.55.a(g)4(ii), Millstone Unit 3 (the licensee) is committed to
develop an ISI program to the 1980 Edition through the winter 1981 Addenda of Section
XI. The licensee has upgraded this program to the 1983 Edition, including the summer
1983 and 1985 Addenda as permitted by 10 CFR 50.55a(g)(4)(iv).
,
iThe purpose of this inspection was to determine whether the licensee ISI of Class 1,2,
and 3 pressure-retaining components was performed in accordance with the requirements
i
of ASME Boiler and Pressure Vessel (B&PV) Code, Section XI,1983 Edition, including the
1985 Addenda,
b.
Observation and Findinas
b.1
ISI Plans and Schedule
The licensee is adjusting the ISI schedule due to the extended outage, as follows: the
First Ten Year Interval began April 23,1986, and the licensee's current schedule for the
completion is at the end of refueling outage six (RFO 6), projected as December 1998.
The ISI plan shows 48 examinations which are required to be completed during RFO 6 to
closecut the first interval. This number may change as the licensee continues with their
self assessment and interval close out review.
The extension from April 23,1996, to December 23,1998, is allowed by the following: a
year extension per ASME Code IWA-2430 to April 23,1997, and the additional extension
for two long shutdowns. The first was 7 months long in 1991 and the current shutdown
)
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(approximately 20 months) will bring the license to an expected closeout of December 23,
1998.
An anticipated start of the Second Interval and Program Plan upgrade to the latest code is
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April 23,1998. This program plan upgrade is currently under way with the anticipated
L
submittal by October 23,1997 (six months prior to implementation as required by 10 CFR
,
I
50,55 a). This would mean the Second Interval ends July 23, 2008 (April 23, 2006, plus
27 months of extended shutdown).
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c.1
Conclusion
The Millstone Unit 3 ISI schedule was adjusted in accordance with the extensions allowed
by the ASME Code, Section XI.
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b.2
Proaram implementation
The inspector reviewed the licensee's ISI Program Manual, which established the
requirements for ASME Code Classes 1,2, and 3 and determined that the Class 1
requirements system boundary was developed in accordance with the requirements for
reactor coolant pressure boundary as defined in 10 CFR 50.2 and the Millstone Unit 3
FSAR. Class 2 and 3 requirements system boundaries were developed in accordance with
Regulatory Guide 1.26 and Millstone Unit 3 FSAR.
 
b.2.1 ASME Class 1 Components
As a sample inspection for Class 1 components, the inspector reviewed the Reactor
Pressure Vessel (RPV) ISI to ensure compliance with ASME Code requirements. The
licensee recognized there were cases where component configuration and/or interference
 
. prevented 100% coverage of welds as required by the code (volumetric or surface -
s
examinations). In cases like welds 4,6,7, and 8 of the RPV where these limitations
,
,
existed, the licensee had submitted Relief Request 1 (RR-1), Revisions 1-3 to the NRC,
Root Cause 3 - Inconsistent work performance coaching and mentoring by managers and supervisors.
i
documented as follows:
The lower shell to-lower head weld #4. This weld is 100% accessible from the lower head
side and, in both circumferential directions, is obstructed by'six core lugs from the lower
shell side of the weld where coverage is limited to only 70% of the required weld volume.
The upper shelllongitudinal welds #6, #7, and #8 examinations were limited to only 37%
of weld #6 and to only 47% of welds #7 and #8 due to nozzle geometry. The licensee
documented that these examinations will be performed to the maximum extent practical at
the end of the first Ten-Year Interval.
Based on the coverage of the examined welds described above, the NRC granted a relief to
RR-1, Rev. 3, in letter A10880, dated March 3,1993. To document the present RPV ISI
inspection results, the licensee prepared RR-1 Revision 4 documenting the non-destructive
examination (NDE) results that exceeded the previous coverage documented in RR-1, Rev.
3. These results are still below the 90% coverage required by 10 CFR 50.55a(g)(6)(ii)(A).
Therefore, the licensee plans to submit, in addition to the RR-1, Rev. 4, an alternative for
the augmented examination for each weld where 90% coverage was not achieved,
c.2.1 Conclusion
Although the licensee's latest RPV NDE results of welds 4,6,7 and 8 show better
coverage of the examined welds than the previous NDE,90% coverage was not yet
achieved. Therefore, the licensee plans to convey these latest results as Revision 4 of RR-
1, along with an alternative for augmented examination for each of the welds with less
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than 90% examined length, to the NRC Office of Nuclear Reactor Regulation (NRR) for
Root Cause 4 - Work processes are complicated and difficult to comprehend, Corrective action plans are in place to address each root cause in the long term. The following corrective actions have been taken to date:
their review.
Each work group onsite is using the Condition Report (CR) system to formally
b.2.2 ASME Class 2 Components
NRC letter of March 3,1993, documenting the review of Millstone Unit 3 first ten-year
interval ISI indicated that the licensee's program was upgraded in Revision 3 to meet the
requirements of ASME B&PV Code, Section XI,1983 Edition, including the 1985 Addenda
'
for Class 2, Examination Category C.F-1 and C-F-2 piping welds. However, the NRR
review of Revision 3 to RR-1 noted that the chemical and volume control system
containing 129 welds, and the intermediate pressure safety injection systeni containing 96
welds have been completely excluded from examination.
The inspector discussed the licensee's actions to address the NRR concerns as follows:
The requirements for selecting ASME Section XI Class 2 pipe welds to the ASME B&PV
Code, Section XI,1983 Edition, including the 1985 Addenda, is based on pipe size and
wall thickness. For the system of high pressure injection, the piping has to be greater than
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4" in diameter and greater than 0.375" in we" thickness to require any ISI NDE. The 129
document adverse conditions in dosimetry compliance to facilitate tracking, trending, and management review for this issue.
: welds in the chemical volume control system and the 96 welds in the intermediate safety -
injection system are located on 6" and 8" diameter, schedule 40 piping (pump suction
lines); this wall thickness is less than 0.375" and, therefore, no NDE is required.- However,
the code requires this size pipe to be included in the total Class 2 population as a 7.5%
sample of the weld population. Therefore, the licensee plans to perform volumetric
examinations for the 7.5% of the 225 weld population (seventeen) during the next
refueling outage (RF06), currently scheduled to commence in October 1998,
c.2.2 Conclusion
The inspector determined that the licensee actions, including the plans concerning
inspection of the previously excluded 129 piping welds in the chemical volume control
system and the 96 piping welds in the intermediate safety injection system, were
acceptable. The inspector noted that the licensee's Class 2 piping ISI observations, made
by NRR, were addressed by the licensee in accordance with the ASME B&PV Code,
Section XI,1983 Edition, including the 1985 Addenda.
b.2.3 ASME Class 3 Components
To assess the adequacy of the ISI performed for the ASME Class 3 components, the
inspector performed a system walkdown of segments of the component cooling and
service water systems pipe supports.
c.2.3 Conclusion
The inspector identified extensive external corrosion on the channel head bolting flange and
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cover of the Component Cooling Water System heat exchanger Nos. 3CCP"E1 A and
3CCP*E18.
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Each Millstone unit management has conducted management briefings with
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The licensee created a trouble report to have maintenance personnel clean and preserve
the affected bolting. No other significant deficiencies were identified.
U3 E2
Eng!neering Support of Facilities and Equipment
E2.1
Steam Generator Tube Rupture (SGTR) Analysis
a.
Insoection Sco_pe (375511
As part of the 10 CFR 50.54f review of the design and licensing basis of the plant, the
licensee identified that one main steam pressure relievirig bypass valve (MSPRBV) out of
service would invalidate the design basis for the SGTR overfill analysis. The MSPRBV's are
used to cool down the reactor coolant system (RCS), on a loss of offsite power (LOOP),
and to maintain adequate margin to prevent overfill of the ruptured steam generator (SG).
Condition report (CR) M3-97-0835 was written to document this condition. The inspector
reviewed the Westinghouse WCAP-13002, " Margin to Overfill Analysis for a SGTR for
Millstone Unit 3 Four Loop Operation," as followup to the design concern documented in
the CR, at well as to further evaluate the engineering aspects of the operational issue
discussed in section U3.01.2 of this inspection report,
b.
Observations and Findinas
WCAP-13002 assumes that cool down of the RCS, during a SGTR event and LOOP,is
accomplished with two SGs via the MSPRBVs. Two SGs are unavailable due to both the
ruptured SG and an assumed singie failure of one MSPRBV. This assumed single failure is
consistent with the generic guidance documented in Westinghouse WCAP-10698, "SGTR
Analysis Methodology to Determhe the Margin to Steam Generator Overfill."
WCAP-10698 analysis methodology included the selection of a reference plant (three loop
plant) that has the potential for th; least margin to overfill. The worst case single failure
for this plant was determined to be the loss of one MSPRBV, since this decreased the
available steam dump capacity (for plant cool down) by 50 percent for the LOOP case.
The loss of an emergency diesel generator (EDG) was not considered the most limiting
case because, although power is lost to a MSPRBV, the rate of filling of the ruptured SG is
also reduced by the loss of components that automatically start to fill the RCS.
The inspector questioned whether the most limiting failure for the SGTR analysis, for a four
loop plant, was the loss of an EDG. A loss of the EDG could result in the inability to
operate two MSPRBVs. This would result in a decrease in the available steam dump
capacity by 67 percent. There was no discussion in WCAP-13002 addressing the loss of
an EDG.
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personnel to emphasize dosimetry compliance expectations with their respective radiation worker populations, in addition, briefings on radiological issues have been presented to craft personnel by senior Health Physics and station management personnel to make field workers aware of radiological compliance deficiencies and worker expectations, Millstone Station has reduced the number of entry points into the Radiological e
Controlled Areas (RCAs),
The radiation worker training program has increased emphasis on dosimetry
*
requirements to radiation workers. Also, Health Physics technicians have been integrated into practical factor training to assist the training department instructors in delivering information to radiation workers, Mechanical one way turnstiles have been ordered and are being introduced at e
select RCA control access points, to serve as additional defense in depth barriers to help achieve optimum compliance.


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A multidiscipline Common Cause Analysis has been completed which determined
c.
Conclusion
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The inspector discussed the concern regarding the most limiting failure for the SGTR
margin to overfill analysis with cognizant licensee personnel. The licensee plans to perform
a specific Unit 3 SGTR analysis to further address questions of this nature. This matter
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will be reviewed further by the NRC as an inspector followup item. (IFl 423/97-02-16)
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.
.
Miscellaneous Engineering issues
failure mechanisms and recommended corrective actions for Health Physics compliance issues.
U3 E8
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E8.1
(Closed) SIL ltem 30: Auxiliary Feedwater Check (AFW) Valve Leakage
References: ACR M3-96-0855 Auxiliary Feedwater Valve Operability
NU Letter B15397, Dated November 1,1995
a.
Inspection Scone (92903)
The inspector reviewed the licensee actions taken and actions planned to resolve a problem
with backleakage through the AFW system check valves.
b.
Observations and Findinas
Check valve leakage in the auxiliary feedwater lines has resulted in elevated piping and
containment penetration temperatures. Prolonged operation at elevated temperatures could
result in damage to the concrete adjacent to the penetrations. To alleviate this concern the
operators monitored the penetration temperatures and, when necessary, operated an AFW
pump to cool the penetrations by pumping the relatively cool water from the demineralized
water storage tank to the steam generators. During this evolution the turbine driven AFW
pump was isolated resulting in a significant increase in the unavailability time of this pump.
Engineering evaluations had been performed to assess the effects of the elevated
temperatures on the penetration concrete temperature and the pipe supports. These
evaluations concluded that operations with temperatures as high as 300 degrees for short
periods would not be detrimental to the operation of the piping or the concrete. However,
those evaluations did not specifically document an assessment of the effects of the
elevated temperatures on valves 3FWA*MOV35D and 3FWA*HV36D. ACR M3-96-855
was issued and documented an evaluation that concluded that the valve performance
would not be impacted by elevated temperatures.
In 1995 the licensee replaced check valve 3FWA*V47, located outside of the primary
containment, in an effort to reduce the backleakage through the "D" AFW penetration.
'
The licensee also planned to replace the two check valves in the same line that are located
inside of the primary containment during the sixth refueling outage. During that time
manual isolation valves were to be installed to facilitate future repairs. After entering the
current unplanned shutdown the licensee considered performing this work prior to restart,
but then decided to do the work in the sixth refueling outage as originally pla 1ed.
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The licensee decision was based on the following factors:
$f
Surveillance procedure SP 3622.3, " Auxiliary Feedwater Pump 3FWA*P2
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Operational Readiness Test," was revised to shut a manual discharge valve to
6 p emgwg-p,
prevent the check valves from being lifted off of their seat during pump tests.
-e
Experience has shown that once the check valves seat, they remain seated.
An operating procedure is in place that includes instructions on reseating the check
*
valves.
The AFW piping temperatures at the containment penetrations are checked and
*
recorded each shift as part of the operator rounds.
Procedures are in place to cool the piping if the temperature exceeds 150 F.
*
The piping has been analyzed to ensure elevated temperatures would not adversely
*
affect system operability.
Following the replacement of check valve 3FWA*V47 and the change to the
*
surveillance procedure there were no entries in the shift manger logs to indicate any
problem with leakage for the last eight months of power operations, prior to the unit
shutdown.
The replacement of the two check valves inside containment is still planned for
*
refueling outage (RFO) 6.
In addition to these considerations the inspector noted that the two check valves
scheduled to be replaced had been inspected during the la.st refueling outage and no
significant deficiencies were identified.
c.
Conclusions
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The inspector reviewed portions of the associated documentation, drawings and
procedures and discussed the issue with the design and system engineers. The inspector
noted that the surveillance procedure change to shut a manual isolation valve during
testing did not affect the previously established testing flow path and did not involve a
significant additional burden on the operators. Also, the most recent operating experience
indicated that the need to frequently cool the penetrations had been eliminated, minimizing
the potential for the condition requiring significant operator attention. The inspector
concluded that the licensee had provided adequate bases for implementing further
corrective actions, as previously planned, during RFO 6. Sllitem 30 is closed.
E8.2 (Closed) SIL ltem 62: ACR 13788 - TSP Basket Modification Safety Evaluation
a.
Insoection Scope (92903)
The inspector reviewed the licensee actions taken to resolve the issues documented in
ACR 1378 _
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b.
Observations and Findinas
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Unresolved item Report (UIR) 107 raised several questions associated with the trisodium
phosphate (TSP) basket modification that was performed by Plant Design Change Request
(PDCR) 94-135. A question as to the validity of the radiological safety evaluation in the
i
PDCR was raised because the licensee safety evaluation was originally written to support
two changes; the addition of the TSP baskets and an increase in the allowable containment
leak rate. The licensee's safety evaluation stated that "This safety evaluation is not valid if
only one of the two changes is approved." The NRC reviewed and approved only the
addition of the TSP baskets in License Amendment No.115, and stated in the associated
NRC safety evaluation that the proposed increase in the containment leak rate would be
considered separately. NRC evaluation and approval of the TSP basket change was based
on the existing assumed containment leakage rate.
The licensee subsequently reviewed the effects on the safety evaluation based on only
having the one change approved. This review determined that the safety evaluation
i
bounded the technical specification status as they existed for plant startup from the 1995
refueling outage and the safety evaluation was revised to reflect this conclusion.
.
Several FSAR discrepancies that were identified were resolved via FSAR change requests.
!
that had been approved by the unit director.
;
c.
Conclusions
The inspector reviewed the associated documentation and discussed the issue with the
responsible engineer and concluded that the licensee had appropriately addressed the
issues documented in the subject ACR. SIL ltem 62 is closed.
E8.3 (Closed) LER 96-047-00 : Seismic Qualification of 4 Kv Circuit Breakers
a.
Insoection Scope (92903)
.
The inspector reviewed the licensee findings and corrective actions taken regarding a
potential seismic concern that the 4160 Volt General Electric (GE) circuit breakers may not
have been adequately restrained when they were not in the fully engaged position.
b.
Observations and Findinas
The 4160 Volt switchgear was seismically qualified with the circuit breakers fully engaged
,
in the operating position. During maintenance or testing activities the circuit breakers may
#
be in the racked-down position, and would be free to move as a result of a seismic event.
This could impact the switchgear cubicle structure. Such an impact could result in the
inadvertent actuation of protective relays mounted on the cubicle doors. Inadvertent
actuation could result in the loss of power to safety equipment. Neither the seismic
qualification report or operating and maintenance manuals discussed this condition and the
plant staff had previously failed to recognize this potential.
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- The licensee removed all safety related circuit breakers that were racked-down from their
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associated switchgear cubicles while long term solutions were evaluated. Also, operating
c-----e we
procedure OP 3370A was revised to ensure that when the breakers are racked down that
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the breakers are restrained or removed from the switchgear cubicles. The method of
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restraining the breakers is by verifying that the elevator handle was forward and latched in
place. This method was based on discussions with GE. Additional reviews to confirm if
any additional actions are required are to be completed prior to restart of the plant.
The inspector reviewed procedure OP 3370A and inspected a breaker in the racked-down
position and found it to be in accordance with the procedure. A plant operator interviewed
at the switchgear was familiar with the requirement and the bases for the requirement for
positioning the elevator handle.
c.
Conclusions
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!
The inspector concluded that the immediate corrective actions appropriately addressed the
issue and that additional reviews are being tracked and scheduled for resolution prior to
plant startup. LER 96-047-00 is closed.
E8.4 (Closed) LER 97-001-00
125 Volt Battery and Charger Surveillance Testing
i
a.
Inspection Scope (92903)
The inspector reviewed the licensee findings and corrective actions taken to resolve issues
'
associated with the battery and battery charger surveillance testing.
b.
Observations and Findinos
in January 1997, the licensee identified two examples where surveillance testing was not
being performed in verbatim compliance with the technical specifications. In one case
surveillance requirement 4.8.2.1.b.3 requires a verification that "The average electrolyte
temperature of six connected cells is above 60 F." in this case, the licensee was
obtaining the temperatures of all 60 cells and verifying the average temperature was above
60 F.
In the other case, surveillance requirement 4.8.2.1.c.4 requires a verification that "Each
battery charger will supply at least the amperage indicated in Table 4.8-2b at 125 Volts for
at least 24 hours." The testing was performed with the battery charger voltage at the
normal operating voltage of approximately 129 Volts.
Although the testing methods appeared to be adequate to ensure equipment operability,
the licensee revised the affected test procedures to ensure verbatim compliance with the
technical specifications. The revised tests were performed with satisfactory results.
c.
Conclusions
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The inspector reviewed the associated surveillance requirement bases and the most recent
surveillance tests and found the licensee actions to be appropriate. These failures


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constitute violations of minor significance and are being treated as Non-Cited Violations,
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consistent with Section IV of the NRC Enforcement Policv. Therefore, LER 97-001-00 is
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closed.
-..-.4.
E8.5 (Ocen) SIL ltem 16: ACR 1935 - Dual Function Valve Testing
(Onen) Unresolved item 96-08-18: Inadequate Inservice Test (IST) Program
Controls
a.
Inspection Scone (92903)
The inspector reviewed the licensee evaluation of the potential for Unit 3 to experience
problems similar to Unit 2 relative to containment isolation valves that have a function to
close at a system operating pressure that is higher than that at which the valves are tesud
for containment isolation purposes,
b.
Observations and Findinas
This issue was initially identified in 1993 by Unit 2 personnel when air operated valves in
.the Unit 2 letdown line did not fully shut against reactor coolant system pressure when
attempting to stop flow to perform a valve repair. The licensee found that the cause was
that the spring preload on the air operators had not been properly set during maintenance.
The immediate concern was resolved by adjusting the spring preloads and verifying closure
of the affected valves by performing a seat leakage test at normal operating pressure. Unit
j
2 engineers also committed to define retest requirements to verify isolation capabilities for
dual function valves at full system pressure.
Unit 3 personnel reviewed this issue and concluded that it was not applicable to Unit 3 for
the following reasons:
The Unit 3 actuator specifications included a valve specific data sheet which clearly
j
*
identifies the maximum shutoff and operating pressure.
i
The actuator setup was specified by the vendor for the maximum shutoff pressure
*
and the actuator was provided with a valve data nameplate which specified the air
pressure settings that correlated to the required actuator spring preload.
The Unit 3 actuator procedures record the spring setting, include a step to re-
*
establish the as found setting and to test the actuator pressure was in accordance
with the nameplate data.
During the review of the valve testing performed on the various valves, the inspector
reviewed the design bases requirements of the isolation valves in the letdown line for Unit
l
3. The letdown line flow path is from the reactor coolant system (RCS) loop piping
l
through two letdown isolation valves (3-RCS*459 and 460), through the regenerative heat
i
exchanger. After the heat exchanger, the piping splits into three parallel flow paths, each
with an orifice and a downstream orifice isolation valve (3-CHS* AV8149A, B, and C).
From the outlet of the orifice isolation valves, the piping connects to a common line which
l
.
!
:


..
..
.
.
.-
l*.,
- -
. +
-
..
-
..
--
.
>
l
.
.
,
,
:
,
'
l'
l
then exits the containment through the inboard and outboard containment isolation valves
(3-CHS*CV8160 and 8152).
-The inspector noted that Section 15.6.2 of the Final Safety Analysis Report (FSAR)
evaluates the effects of a failure of a smallline carrying primary coolant outside
containment. The analyses indicates that the most severe pipe rupture would be a
complete severance of the letdown line outside of containrrent. The FSAR states that the
;
operator would isolate the letdown line rupture by closing the letdown orifice isolation
!
valves (3-CHS* AV8149A, B, and C) followed by the pressurizer low level isolation valves
(3-RCS*459 and 460). Ahernatively, the operator would close the containment isolation
i
valves (3-CHS*CV8160 and 8152) to isolate the rupture,
The inspectors found tnat the licensee was in the process of adding the 3-
CHS* AV8149A,B,C valves into the IST program. However, the 3-RCS*459 and 460
valves weia not included in the IST program, nor had they been addressed by a recent
licenseo review of the IST program. The licensee reviewed this question and found that
j
l
various design documents had conflicting information and also that all of the valves inside
'
of containment were powered from the same train of electrical power. Condition report
M3-97-0866 was issued by the licensee on March 21,1997 to document these questions.
These issues are similar to those addressed by NRC unresolved item 50-423/96-08-18
which was issued to track licensee actions concerning inadequate IST Program controls
and testing. License actions to address these additional CR M3-97-0866 questions will be
reviewed as part of the unresolved item review.
c.
c.
Conclusions
NRC review of the adequacy of the dual function valve testing is continuing and SIL ltem
16 remains open. NRC unresolved item 50-423/96-08-18 remains open pending NRC
review of the IST program issue resolution.
E8.6 (Closed) URI 96-201-17: Auxiliary Feedwater (AFW) Pump Lubrication Schedule
(Closed SIL ltem 18 - Partially Closed)
a.
Inspection Scope (92903)
The inspector reviewed the licensee findings and corrective actions taken regardinh the
adequacy of the AFW pump bearing lubrication.
b,
Observations and Findinas
In April 1996, an NRC inspection team questioned the bases for caution statements in the
AFW surveillance tests that required the pump bearings to be manually prelubricated prior
to a pump start if the pump had not been operated in the previous 40 days. Since the
surveillance test only operates the pumps quarterly, the pump could receive an automatic
j
start signal, after a period greater than 40 days without the procedurally mandated, manual
;
prelubrication.
- -. - -..
..
..
- -. -
..
-... -
.
. -.-. -. - _.
.. -,
- -
.
l
..
The licensee reviewed this concern with the pump vendor and concluded that the pumps
could be started without prelubrication after an idle period of up to 113 days. This
conclusion was based on the light load on the bearings, experience with similar pumps,
and adequate residual oil on the bearings to provide lubrication for the initial one or two
i
seconds until the shaft driven luba oil pumps provide considerable quantities of oil to the
bearings.~
The operating and surveillance procedures and the pump vendor manual have been revised
to reflect this evaluation.
c.
Conclusions
The inspector concluded that the licensee had appropriately addressed this issue.
Unresolved item 50-423/96-201-17 (Partial of SIL ltem 18) is closed.
'
l
. _ _.
.
l
-


!
U.S. Nuclear Regulatory Commission
IV Plant Support
(Common to Unit 1, Unit 2, and Unit 3)
R1
Radiological Protection and Chemistry Controls
R 1.1
Radioloaical Protection Proaram
a.
Insoection Scope (83750)
The inspector reviewed the circumstances surrounding multiple examples of workers
entering the RCA without proper dosimetry. These instances occurred from March through
April 1997, and included one instance which occurred during the period of the specialist
inspection.
b.
Observations and Findinas
Unit 1
. On March 1,1997, Unit 1 identified a new person to serve as Radiation Protection -
Manager (RPM). The inspector reviewed the designated individuals training and
qualifications against the requirements set forth in Unit Technical Specification 6.3.1, and
determined that the designated RPM met the qualification requirements.
On April 13,1997, a work group entered the liquid radwaste facility to perform work in the
"A" and "B" Concentrated Waste Tank cubicle. This area is a posted Locked High
Radiation Area (LHRA). One of the workers failed to obtain an electronic dosimeter as
required by plant procedures as required by unit Technical Specification 6.11 for entry into
an LHRA. After working in the LHRA for a period of time, the worker realized he was not
wearing electronic dosimetry, and exited the area. The workers exposure was calculated
to be 70 millirem, which was added to his official dose of record. Procedure RPM 5.22
requires radiation workers to comply with written instructions, including RWPs, from the
radiation protection staff. Failure to adhere to the licensee's radiation protection program,
specifically procedure RPM 5.22, is a violation of 10 CFR 20.1101. (VIO 245/97-02-17)
Unit 2
Since the last specialist inspection in this area, Unit 2 has experienced three additional
incidents involving workers i
no RCA without electronic dosimetry. During the last
specialist inspection (50-336/9L01), three earlier examples of this violation had been
identified. Corrective actions taken by the licensee to address this issue have failed to
prevent a recurrence. Corrective actions taken at the time of this inspection included
reducing the number of access points into the RCA; posting of a radiation protection
technician near the main RCA access point to observe workers entering the RCA; and
l
working with the training department on the development of an enhanced radiation worker
training program to include use of a mock-up RCA facility. Failure to adhere to the
l
licensee's radiation protection program, specifically procedure RPM 5.22,is a violation of
!
10 CFR 20.1101. (VIO 336/97-02-17) This is a repeat violatio._.
.
. - _
.-
.-. - -
_. -
--
-..
.
o
.
.
 
l B16619%ttachment 1\\Page 3
_ Unit 3
During this specialist inspection, on April 29,1997, a contractor worker entered the RCA
i.
'
'
without hi.s thermoluminescent dosimeter (TLD). The worker's TLD was later found
Results to date:
outside the RCA in the turbine building, where he had previously been working. Since the
O.0002
TLD is utilized to determine dose of record, all workers assigned a TLD must wear it when
in the RCA. Failure to adhere to the licensee's radiation protection program, specifically
procedure RPM 5.22, is a violation of 10 CFR 20.1101. (VIO 423/97-02-17).
;
Site Health Physics
l
Recently the licensee was sent a 10 CFR 21 notification by a vendor regarding the
operability of a condenser R-meter utilized to maintain traceability of the licensee's
calibration source to the National Institute of Standards and Technology (NIST) primary
i
calibration standard. The inspector reviewed the actions taken by the licensee, and
determined that appropriate corrective actions occurred, that survey instrumentation
utilized were properly calibrated, and that no erroneous data or calibrations occurred at the
licensee's f acility,
c.
Conclusions
Licensee corrective actions for a previously identified violation involving radiation worker
practices have not been successfully implemented so as to prevent recurrence. Since the
last specialist inspection in this area, concluded on February 7,1997, five additional
examples have been identified, including one in which the worker entered a posted, locked
high radiation area.
R1.2 Radwaste Proaram
l
a.
Insoection Scope (86750)
l
.
.
l
$g 00001-
The inspector reviewed actions taken by the licensee to remediate the conditions found in
L
the Unit 1 liquid radwaste f acility, previously identified by the NRC (NRC Inspection Report
l
50-245/95-35), together with actions taken to ensure appropriate management attention is
focused on this program area in the future. Additionally, the inspector reviewed the
management focus on the liquid radwaste program at Unit 3.
b.
Observations and Findinos
l
l
Unit 1
l
The licensee recently completed the removal of six major processing vessels / tanks from
the liquid radwaste f acility. These included two vessels that were still in service in 1995,
although both were also actively leaking spent filter media. During this inspection, the
inspector toured all areas of the liquid radwaste facility; except sealed demineralizer/ filter
cubicles (radwaste demineralizers [2] and spent fuel pool filters [2)) and the spent resin
,
tank. Recent photographs of these areas, except the radwaste domineralizers, were
reviewed by the inspector rather than actual entry to these facilities, due to radiation
l
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!
_ _
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.
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.
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exposure considerations. Examination of the radwaste demineralizers has not yet been
E E
j
N
l
started by_the licensee.
In general, all previously identified areas of radwaste materials located on floors and other
vertical surfaces have been cleaned up, and in-service processing vessels have been
inspected and determined to be usable, inspection of the "A" and "B" floor drain collector
i
tanks was not completed at the time of this inspection, although the inspector did examine
the interior of the "B" collector tank during 1.11s inspection. The inspector reviewed the
actions taken by the Engineering Department to inspect the tanks, pumps and piping in the
facility and determined that the conclusions reached on the continued use of certain
components was reasonable. The inspector was also apprised of the current project
status, its interim completion date (July 15,1997) when the facility would be ready to
support plant operations, and items that would still need to be addressed after July 15,
1997, including the purchase and installation of a new sludge tank.
Of particular interest to the inspector was actions taken by the licensee to prevent a
recurrence of the radwaste problems, specifically actions taken to ensure appropriate
management oversight of the systems. Previous unit management focused on the quantity
of radionuclides discharged in the liquid effluent from the unit, and determined that since
mthis number was trending down, the radwaste facility was functioning properly.:
Additionally, the person designated at the unit as responsible for the safe and appropriate
operation of the facility was an operations assistant, a position five levels below the Unit
Director.
The inspector discussed the current management of the unit's radwaste facility with the
Operations Manager assigned oversight responsibility, his supervisor, the Operations
Director, and other staff at the unit involved in the radwaste program. By placing
responsibility for the safe operation of radwaste under an Operations Manager (one of two
in the unit), the system is subject to more management attention and oversight than
previously. In addition, the focus within the unit appears now to be placed on operation of
the radwaste facility in a manner consistent with plant safety, operational reliability,
conformance with plant design documents and minimization of effluent discharge. The
inspector indicated that this would be an area of continued focus, especially when the
radwaste facility was fully operational again.
Unit 3
At Unit 3, while the amount of radioactivity discharged to the environment remains low, no
clear management oversight appears to exist During this inspection, the inspector
interviewed the unit Chemistry Supervisor, under whom the Primary Equipment Operator -
Radwaste, now works, and the Unit Director. Neither could identify a single point of
contact within the unit's management as being respont.ble for liquid radwaste. Since a
lack of this type of management focus has been identified as a principle root cause of the
radwaste problems which occurred in Unit 1, this similar lack of clear management
l
oversight at Unit 3 is of concern to the NRC. While no violation is evident, this area
l
requires more managerial attention,
i
,,
.,
,_


_.
E E
.
mr
_=.
"
_
Error rate = RCA Entry Er orstrotal RCA Entries The corrective actions completed to date have had a beneficial effect in minimizing
__
_ _ _ _ _
.
.
_
_
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*
 
c.
Conclusions
l
Significant physical improvements ;n the Unit 1 liquid radwaste facility have been made,
although work has not yet been completed. The Unit has also placed heightened
management attention to this program area, although the effectiveness of this heightened
,
,
l
dosimetry compliance events at Millstone Station. Our goal is to have zero dosimetry compliance issues. Our actual performance during the month of June through July 23, 1997 documented that one person entered the RCA without an electronic dosimeter out of 90,842 entry events (0.00001 error rate). While we have not met our goal of zero dosim9'.ry infractions, this indicates a favorable trend over our previous year to date
focus will have to be evaluated once the physical remediation of the facility is completed.
At Unit 3, there continues to be a lack of clear management oversight for the liquid
radwaste system and program.
l
V. Manaaement Meetinas
i
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at
separate meetings in each unit at the conclusion of the inspection. The licensee
acknowledged the findings presented.
X I.2
Final Safety Analysis Report Review
A recent discovery of a licensee operating their facility in a manner contrary to the updated
final safety analysis report (UFSAR) description highlighted the need for additional
verification that licensees were complying with UFSAR commitments. All reactor
inspections will provide additional attention to UFSAR commitments and their incorporation
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.
Inconsistencies were noted between the wording of the UFSAR and the plant practices,
procedures and/or parameters observed by the inspectors, as documented in Sections
U1.E1.3, U2.E2.1, U3.E1.1, U3.E8.2. and RI
X3
Management Meeting Summary
On April 30,1997, the NRC staff participated in a publicly observed meeting with licensee
representatives to discuss the licensee's progress in facilitating the restart of all three
Millstone units. A summary of this meeting, to include licensee slides, was published on
May 12,1997 and has been made available in the NRC Public Document Room.
l
,
,
I
performance. It is expected that continued emphasis will help eliminate dosimetry non-compliance issues.
l


. __.
The Corrective Steps That Will be Taken to Avoid Further Violations NNECO will continue to monitor and trend Millstone Station radiation protection program compliance by use of a station-wide trending program and will evaluate the long term effectiveness of corrective actions by performing a self-assessmer.t.
.
_. _ - -
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_
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._
_
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._..-..
_. _ - _ - _ _ _ ~
*
.
.
;


INSPECTION PROCEDURES USED
Date When Full Compliance Will be Achieved -
b
~
IP 37551:
NNECO is currently in full compliance with the requirements of.10 CFR 20.1101 and Paragraph 1.1 of procedure RPM 5.2.2, " Basic Radiation Worker Responsibilities."
Onsite Engineering
,
f
IP 40500:
Licensee Self-Assessments Related to Safety issues inspections
IP 62703:
Maintenance Observations
}
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
f
IP 73753
Inservice Inspection
[
IP 83750:
Occupational Radiation Exposure
t
IP 86750:
Solid Radioactive Waste Management and Transportation of
j
Radioactive Materials
IP 92700:
Onsite follow-up of Written reports of Nonroutine Events at Power
j
Reactor Facilities
;
IP 92901:
'!Iowup - Operations
,
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
,
i
i
!
.
 
...
-
. - -. -
o
e


ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
URI 50 245/97-02-01
U 1.01.4
Failure to Trend CRs
URI 50-245/97-02-02
U 1.01.4
RP-4 interface with lower
tier reporting processes
,
'
URI 50-245/97-02-03
U1.03.1
NGP 2.25 reportability
l
determination and LER
processing
.,
URI 50-245/97-02-04
U1.08.1
Non OA lamp bulb usage
eel 50-245/97-02-05
U 1.E1.1
Inadequate corrective
action
}
eel 50-245/97-02-06
U 1.E 1.1
Appendix J leak testing
'
VIO 50-245/97-02-07
U1.E1.2
Inadequate procedure
control of CIVs
l
EEI 50-245/97-02-08
U1.E1.3
Operation of LPCI system
I
beyond licensing basis
eel 50-245/97-02-09
U1.E1.3
Inoperable LPCI heat
.
.
exchangers
6 -* * ' -
EEI 50-245/97-02-10
hN*" * -
U 1.E1.3
enemuim ene
UFSAR discrepancies
,t--wemsm a misemag i,eep
eel 50-245/97-02-11
_e ye, w w e
U 1.E8.2
_ _..,. _.
Leakage of CU-29 valve
.,e
eel 50-336/97-02-12
. ee,
U2.E8.1
w
Inadequate Surveillance
Procedures
VIO 50-336/97-02-13
U 2.E8. 2
Corrective action failure for
single failure vulnerability
URI 50-423/97-02-14
U3.M2.1
Maintenance and
Configuration of pipe
supports
IFl 50-423/97-02-15
U3.M7.1
Maintenance corrective
action /ASME code
compliance
IFl 50-423/97-02-16
U3.E2.1
Steam generator tube
rupture analysis
VIO 50-245/336/423
97-02-17
R 1.1
Failure to adhere to
radiation protection
program
Closed
VIO 50-336/95-11-01
U2.E8.1
URI 50-336/95-25-03
U2 E8.2
URI 50-336/95-27-01
U2.E8.3
URI 50-336/95-81-01
U2.E8.4
IFl 50-336/95-201-07
U2.E8.5
VIO 50-336/96-01-06
U 2.M8.1
VIO 50-336/96-04-08
U 2.M8.2
\\
 
'
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!
i
I
O
.
*
-90
URI 50-336/96-05-11
U2.E8.6
.
URI 50-423/96-201-17
U3.E8.6
'
Updated
URI 50-245/96-06-02
U 1.M8.1
eel 50-336/96-08-06
U 2.08.1
f
VIO 50-336/96-08-07
U2.M8.3
 
eel 50-336/96-08-10
U2.M8.4 -
.
:
eel 50-336/96-09-10
U2.E8.7
eel 50-336/96-201-29
U2.E8.4
,
URI 50-423/96-01-07
U3.01.2
,
eel 50-423/96-201-33
U3.M8.3
URI 50-423/96-08-18
U3.E8.5
;.
The followina LERs were also closed durina this inspection:
:
Docket Number 50-245
,
!
96-12.
:
 
i
Docket Number 50-336
i
!
96-16
96-37
i
Docket Number 50-423
* 96 27
]
96-32
96-41
,
'j.
96-47
 
97-01
97-02
 
97-05
'
97-06-01
,
97-08
:
i
97-09
l
97-12
,
i
i.
i
l
,
!
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.
f
_
_.
-
_
_
_. _.
 
-
__
_ _ _ _
_ _ _ ____ _.. _. __.._... _ _. _ _ _ _ _ _ _ _
_ _. - _. _ _. _ _ _.....
-
*
!
e
f
 
LIST OF ACRONYMS USED
ACR(s)
adverse condition report (s)
AFW
auxiliary feedwater
'
AMSAC
mitigation system actuation circuitry
ANSI /ANS
American National Standards institute /American Nuclear
!
ARP
Alarm Response Procedure
ASME
American Society of Mechanical Engineers
l
ASTM
American Society of Testing and Materials
l
ATWS
anticipated transie'nt without scram
AWO(s)
automated work order (s)
CEBPS
containment and enclosure building purge system
CFR
Code of Federal Regulations
CIAS
containment isolation actuation signal
CR(s)
condition report (s)
DCM
design chtnge manual
DCN
design change notice
'
EBFS
enclosuro building filtration actuation system
ECP
estimated control rod position
ECT
eddy current testing
E&DCR(s)
Engineering & Design Coordination Reports
]
EDG
emergency diesel generator
i
EEI
escalated enforcement item
ER
Engineering Record
ERT
event review team
ESAS
engineered safeguards actuation system
ESF
engineered safety feature
ESW
emergency service water
j
EWR
engineering work request
'
FIN
Fix-It-Now
FSAR
Final Safety Analysis Report
FTS
Fin Team Supervisor
FWS
feedwater system
GL
Generic Letter
gpm
gallons per minute
HELB
high energy line break
,
HP
health physics
I&C
instrument and control
ICAVP
Independent Corrective Action Verification Program
IFl
inspector follow item
ILRTis)
integrated leak rate test (s)
IP(s)
inspection procedure (s)
IPTE(s)
Infrequently Performed Test or Evolution (s)
lR(s)
Inspection Reports (s)
ISI
inservice inspection
IST
in service testing
HP
health physics
LER(s)
licensee event report (s)
..
 
s'
j
 
92
LHRA
locked high radiation area
LLRT
local leak rate testing
,
LOCA
loss of coolant accident
LOOP
loss of offsite power
i
LPCI
low pressure coolant injection
j
MRT
management review team
j
MSPRBV
main steam pressure relieving bypass valve
NCR(s)
nonconformance report (s)
NDE
non-destructive examination
NGP(s)
nuclear guidance procedure (s)
NIST
National Institute of Standards and Technology
NNECO
Northeast Nuclear Energy Company
NPSH
net positive suction head
NRC
Nuclear Regulatory Commission
NRR
Nuclear Reactor Regulation
NSAB
nuclear safety assessment board
NSAL
Nuclear Safety Advisory Letter
NSIC
Nuclear Safety Information Center
NS&O
nuclear safety and oversight
NUQAP
Northeast Utilities Quality Assurance Program
NUREG
Nuclear Regulation
NUSCO
Northeast Utilities Service Company
NVLAP
National Voluntary Laboratory Accreditation Program
OCA
Office of Congressional Affairs
OP(s)
operating procedure (s)
P&lD
piping & instrumentation diagrams
PAO
Public Affairs Office
PDCR
plant design change record
 
PDR
Public Document Room
PMMS
production maintenance management system
PORC
plant operation review committee
PTSCR
proposed technical specification change request
{
OA
quality assurance
'
OAS
Quality and Assessment Services
RCA
radiologically controlled area
RCS
reactor coolant system
RI
Region I
,
RPV
reactor pressure vessel
R W P(s)
radiation work permit (s)
SER(s)
safety evaluation report (s)
SFP
spent fuel pool
SG
steam generator
SGCS
safety grade cold shutdown
SGTR
steam generator tube rupture
SIL
significant items list
SORC
site operations review committee
SPO
Special Projects Office
SRO
senior reactor operator
 
,
--7
-
g
,
,
r6.
W-
 
STA
shift technical advisor
SWSOPI(s)
service water system operational performance inspection (s)
TDAFW
turbine driven auxiliary feedwater
TEMA
Tubular Exchanger Manufacturers Association
TER
Technical Evaluation Report
TLD(s)
thermo-luminescent dosimeter (s)
TOE
team qualified expert
TS(s)
technical specification (s)
TSC
Technical Support Center
UFSAR
updated final safety analysis repo t
UIR(s)
unresolved indication report (s)
URl(s)
unresolved item (s)
VIO
violation
i
\\
{
_. _
}}
}}

Latest revision as of 03:32, 23 May 2025

Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-245/97-02, 50-336/97-02 & 50-423/97-02 Issued on 970624.Actions Will Be Examined During Future Insp
ML20217Q000
Person / Time
Site: Millstone  Dominion icon.png
Issue date: 08/14/1997
From: Durr J
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To: Carns N
NORTHEAST NUCLEAR ENERGY CO.
References
50-245-97-02, 50-245-97-2, 50-336-97-02, 50-336-97-2, 50-423-97-02, 50-423-97-2, NUDOCS 9708290104
Download: ML20217Q000 (3)
v • d • e


Text

August 14, 1997

SUBJECT:

COMBINED INSPECTION REPORT NOS. 50 245/97-02,50-336/97 02, AND 50-423/97-02 (REPLY)

Dear Mr. Carns:

This letter refers to your July 25,1997 correspondence, in response to our June 24,1997 letter.

Thank you for informing us of the corrective and preventive actions documented in your letter. These actions will be examined during a future inspection of your licensed program.

Your cooperation with us is appreciated.

Sincerely, ORIGINAL SIGNED BY:

Jacque P. Durr Chief, inspections Special Projects Office Office of Nuclear Reactor Regulation Docket Nos. 50 245;50-336:50-423 200087

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M. H. Brothers, Vice President - Millstone, Unit 3 J. McElwain, Unit 1 Recov< ry Officer

- M. Bowling, Jr., Unit 2 Recovery Officer D. M. Goebel, Vice President, Nuclear Oversight J. K. Thayer, Recovery Officer, Nuclear Engineenng and Support P. D. Hinnenkamp, Director, Unit Operations =

F. C. Rothen, Vice President, Work Services J. Stankiewicz, Training Recovery Manager R. Johannes, Director - Nuclear Training

- cc w/cy of Licensee Response Letter:

_ L. M. Cuoco, Esquire J. R. Egan, Esquire V. Juliano, Waterford Library.

' J. Buckingham, Department of Public Utility Control S. B. Comley, We The People State of Connecticut SLO Designee D. Katz, Citizens Awareness Network (CAN)

R. Bassilakis, CAN J. M. Block, Attorney, CAN -

S. P, Luxton, Citizens Regulatory Commission (CRC)

Representative T. Concannon E. Woollacott, Co Chairman, NEAC

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Mr. N. Distribution:

Region I Docket Room (with ggpy of concurrences)

Nuclear Safety Information Center (NSIC)

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FILE CENTER, NRR (with Orioinal concurrences)

NRC Resident inspector B. Jones, PIMS/ DISP M. Kalamon,- RPO, RI W. Lanning, Deputy Director of Inspections, SPO, RI D. Screnci, PAO W. Travers, Director, SPO, NRR

- J. Andersen, PM, SPO, NSR M. Callahan, OCA R. Correia, NRR W. Dean, OEDO l

- S. Dembek, PM, SPO, NRR G. Imbro, Deputy Director of ICAVP Oversight, SPO, NRR

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D. Mcdonald, PM, SPO, NRR P. McKee, Deputy Director of Licensing, SPO, NRR L. Plisco, Chief, SPO, NRR S. Reynolds, Technical Assistant, SPO, NRR t

inspection Program Branch (IPAS)

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DOCUMENT NAME: 1:\\ BRANCH 6\\REPLYLTR\\9702 REP To seesive e copy of this document. Indsete in the boa: *C" = Copy without attachment! enclosure

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NAME-JFuria nny JWhite#"

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/97 0FF/CIALRECORDCOPY

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Nuclear Energy m,,one sa, ro.n swoo Nonheut Nuclear EnerFy Company P.O. Bos 128 Weierford. CT 06385-0128 (860) 447 1791 Fu (860) 444 4277 The Northeast Utihties Systera JUL 2 51997 Docket tios. 50-245 50-336 50-423 i

B16619 Re: 10CFR2.201

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U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Millstone Nuclear Power Station, Unit Nos.1,2 and 3 Facility Operating License Nos. DPR-21, DPR-65, NFP-49 Reply to a Notice of Violation Inspection 50-245/97-02: 50-336/97-02: 50-423/97-02 in a letter dated June 24,1997,W the NRC transmitted the results of an inspection conducted at the Millstone Station from March 11,1997, to May 19,1997. The NRC

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Inspection Report concluded that Northeast Nuclear Energy Company (NNECO) failed to properly impleme..' our rad;otion protection program as demonstrated by having five instances of personnel entering the RCA without wearing a functional electronic dosimeter or TLD, These included one instance at Millstone Unit No.1, three instances at Millstone Unit No. 2, and one instance at Millstone Unit No. 3.

On behalf of Millstone Unit Nos.1,2, and 3, Attachment 1 provides NNECO's reply to the Notice of Violation pursuant to the provisions of 10CFR2.201.

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  • Wayne D. Lanning to Bruce D. Kenyon,'NRC Combined inspection 50-245/97-02; 50-336/97-02; 50-423/97-02 and Notice of Violation," dated June 24,1997.

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B1661thPage 2 i

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Commitments

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The following are NNECO's subsequent. actions which are committed to by;this l

response:

R B16619 1 A station-wide trending program, which will provide a tool to assess the effectiveness of near term corrective actions for human performance, will

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be in place by September 30,1997.

B16619 - 2 The long term effectiveness of corrective actions will be evaluated by performing a self-assessment. This will be completed by March 31,1998.

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LShould you have any questions regarding this submittal, please contact Mr. Ravi Joshi

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at (860) 440 2080.

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Very truly yours,

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NORTHEAST NUCLEAR ENERGY COMPANY

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Senior Vice President and Chief Nuclear Officer

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Attachments (1)

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H. J. Miller, Region i Administrator cc-S. Dombek, NRC Project Manager, Millstone Unit No.1

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- T. A Eastick, Senior Resident inspector, Millstone Unit No.1 D. G. Mcdonald Jr., NRC Senior Project Manager, Millstone Unit No. 2

. D. P. Beaulieu, Senior Resident inspector, Millstone Unit No. 2 J. W. Andersen, NRC Project Manager, Millstone Unit No. 3 A. C. Cornel Senior Resident inspector, Millstone Unit No. 3

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.W. D. Travers, PhD., Director, Special Projects Office -

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-W. D. Lanning, Deputy Director, inspections, Special Projects Office.

' J. P. Durr, Branch Chief, inspections, Special Projects Office

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Docket Nos. 50-245 50-336 EQ:d23

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B16619

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Attachment 1 Millstone Unit Nos.1,2, and 3 Facility Operating License Nos. DPR-21, DPR45, NFP-49 i

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Reply to a Notice of Violation NRC Combined Inspection Report 50-245/97-02,50-336/97-02 and 50-423/97-02

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July 1997

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B16619\\ Attachment 1\\Page 1 Millstone Unit Nos.1,2, and 3 Facility Operating License Nos. DPR 21, DPR-65, NFP-49

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Reply to a Notice of Violation Restatement of Violation Title 10, Code of Federal Regulations, Part 20.1101 (10 CFR 20.1101) requires, in

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part, that licensees develop and implement a radiation protection program. Paragraph 1.1 of procedure RPM 5.2.2, " Basic Radiation Worker Responsibilities," r0 quires, in part, that workers entering the radiologically controlled areas (RCAs) con; ply with instructions provided by the radiation protection staff, including those instructions contained in radiation work permits (RWPs). All entries to the RCA require that station radiation workers be signed in on a general or specific radiation work permit (RWP)

and wear a functioning digital alarming dosimeter and thermoluminescent dosimeter (TLD).

i Contrary to the above, five instances of personnel entering the RCA without weanng a functional electronic dosimeter or TLD were identified. These include orso '.1 stance in i

Unit 1 on April 15,1997; three instances in Unit 2, one each on March 5,1997, March j

7,1997, and April 15,1997; and one instance in Unit 3 on April 29,1997.

l This is a Severity Level IV violation (Supplement IV) for Docket Nos. 50-245, 50-336, and 50-423.

Reason For The Violation Northeast Nuclear Energy Company (NNECO) agrees with the cited violation. This violation was caused by inadequate human performance and was a repeat of the same type of problems identified by Notice of Violation 50-336/97-01-09.

Corrective Steps Taken and Results Achieved A Condition Report (CR), " Adverse Trends in Personnel Performance," was written on May 6,1997, to identify common / root causes and recommend corrective actiona with regards to adverse trends in personnel performance. The adverse trends in human performance were seen in Health Physics issues (lack of proper dosimetry).

A Common Cause Analysis was conducted and the following root causes were identified in the radiation protection program area:

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Root Cause 1 - Inconsistent reinforcement of site performance expectations by managers and supervisors.

Root Cause 2 - Failure of management to effectively establish and communicate a site accountability system.

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Root Cause 3 - Inconsistent work performance coaching and mentoring by managers and supervisors.

Root Cause 4 - Work processes are complicated and difficult to comprehend, Corrective action plans are in place to address each root cause in the long term. The following corrective actions have been taken to date:

Each work group onsite is using the Condition Report (CR) system to formally

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document adverse conditions in dosimetry compliance to facilitate tracking, trending, and management review for this issue.

Each Millstone unit management has conducted management briefings with

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personnel to emphasize dosimetry compliance expectations with their respective radiation worker populations, in addition, briefings on radiological issues have been presented to craft personnel by senior Health Physics and station management personnel to make field workers aware of radiological compliance deficiencies and worker expectations, Millstone Station has reduced the number of entry points into the Radiological e

Controlled Areas (RCAs),

The radiation worker training program has increased emphasis on dosimetry

requirements to radiation workers. Also, Health Physics technicians have been integrated into practical factor training to assist the training department instructors in delivering information to radiation workers, Mechanical one way turnstiles have been ordered and are being introduced at e

select RCA control access points, to serve as additional defense in depth barriers to help achieve optimum compliance.

A multidiscipline Common Cause Analysis has been completed which determined

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failure mechanisms and recommended corrective actions for Health Physics compliance issues.

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l B16619%ttachment 1\\Page 3

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Results to date:

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Error rate = RCA Entry Er orstrotal RCA Entries The corrective actions completed to date have had a beneficial effect in minimizing

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dosimetry compliance events at Millstone Station. Our goal is to have zero dosimetry compliance issues. Our actual performance during the month of June through July 23, 1997 documented that one person entered the RCA without an electronic dosimeter out of 90,842 entry events (0.00001 error rate). While we have not met our goal of zero dosim9'.ry infractions, this indicates a favorable trend over our previous year to date

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performance. It is expected that continued emphasis will help eliminate dosimetry non-compliance issues.

The Corrective Steps That Will be Taken to Avoid Further Violations NNECO will continue to monitor and trend Millstone Station radiation protection program compliance by use of a station-wide trending program and will evaluate the long term effectiveness of corrective actions by performing a self-assessmer.t.

Date When Full Compliance Will be Achieved -

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NNECO is currently in full compliance with the requirements of.10 CFR 20.1101 and Paragraph 1.1 of procedure RPM 5.2.2, " Basic Radiation Worker Responsibilities."

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