IR 05000245/1997207
| ML20198P126 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/09/1998 |
| From: | Durr J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20198P122 | List: |
| References | |
| 50-245-97-207, 50-336-97-207, 50-423-97-207, NUDOCS 9801220014 | |
| Download: ML20198P126 (89) | |
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U.S. NUCLEAR REGULATORY COMMISSION .
REGION I
: Docket Nos.: 50 245 50-336 50-423 Report Nos.: 97 207 97 207 97 207 License Nos.: DPR 21 DPR-65 . NPF-49 Licensee: Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06385 Facility: Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at: Waterford, CT Dates: October 2,1997 - November 30,1997 '
Inspectors: T. A. Eastick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Corne, Senior Resident inspector, Unit 3 P. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident inspector, Unit 2 B. E. Korona, Resident inspector, Unit 3 J. T. Furia, Sr. Radiation Specialist, RI L. L. Scholl, Reactor Engineer, RI G. C. Smith, Sr. Physical Security Specialist, RI N. J. Blumberg, Project Engineer J. W. Andersen, MP3 Project Manager, NRR A. Fresco, NRC Contractor J. H.iggins, NRC Contractor S. Wong, NRC Contractor J. Cadwell, NRC Contractor M. Plunkett, NRC Contractor Approved by: Jacque P. Durr, Chief i inspections, Special Projects Office, NRR P 00N 245 G- PDR b
_ __ _ . . TABLE OF CONTENTS EXECUTIV E SU MMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv U 1.1 O per ati o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 U101 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 U108 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . 3 U 1.Il M ai nt enanc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 U1 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 U1 Ill Engineering .................................................7 Conduct of Engineerino . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 U1 E1 U 2.1 O p e r ati o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 U2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 11 . U 2.ll Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 U2 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 U2 M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . . 15 U2 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . 17 U2.llt Engineering ................................................18 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 U2 E1 U2 E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . 19 U2 E8 hiiscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 21 U2.1 Operations . . . . .............................................24 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 U3 01 U3 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . 26 U3 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . 27 U3 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . 34 U 3.11 M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 U3 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 U3 M2 Maintenance and Material Condition of Facilities and Equipment . . 38 U3 MB Miscellaneous Mairtenance issues . . . . . . . . . . . . . . . . . . . . . . 44 U3.Ill Engineering ................................................47 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 U3 E1 U3 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . 49 U3 E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . 52 U3 E8' Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 55 ii M ~ ~ _ _ . _ _ _ _ _ _ _ _ _ _
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IV Plant Support . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 6 ^ R1 . Radiological Protection and Chemistry Controls . . . . . . . . . . ._. . 66_ R5 Staff Training and Qualification in Radiological Protection and ,
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C he mi s tr y . . . . . . . . . . . . . . - . . . . . . . . . . . . . . . . . . . . . . . . . .' 71
' -R7 Quality Assurance in Radiological Protection and Chemistry Activities 72 >
R8 Miscellaneous Radiological Protection and Chemistry Issues . . . , . 72 , S8 ; Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . . . 73 F1 Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . 74 V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............77 * X1 Exit Meeting Summary . . . . . . . . . . . . . . ...............77
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EXECUTIVE SUMMARY Millstone Nuclear Power Station - 1 Combined Inspection 245/97 207; 336/97 207; 423/97 207
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i Operations
-* At Unit 1, operations response to an unplanned entry into a Red shutdown risk i'
condition was less than adequate. During the event, command and control of the - shif t was weak and without clear expectations as to who was responsible for - making the appropriate decisions to return the unit to a Vallow shutdown risk condition. The issue of command and control within the management of the *
. operations department was identified in an earlier NRC report 97 202, as a problem area. The licensee took steps to ensure that the roles and responsibilities of the recently appointed operations and assistant operation managers, were clearly ,
defined under a new reporting structure. This event demonstrates the need for continued management support and direction to ensure adequate command and control within the operating shifts. (Section U1.01.2)
* At Unit 2, overall operator performance during the inspection period continued to be very good. Changes in plant conditions to support maintenance activities, including the swap in the protected f acility from facility "B" to facility "A", were well controlled and event free. Strong pre-evolution br'efings contributed to this good performance. (Section U2.01.1) * At Unit 2 operators temporarily swapped from the "B" to the "C" reactor building closed cooling water heat exchanger ior 5 minutes, but did not align service water to the "B" heat exchanger as specified in the operating procedure. An unresolved item was opened to allow NRC review of the final root cause evaluation for this licensee-identified concern, and to evaluate whether administrative procedures allowed operators to N/A a step in the operating procedure rather than process a procedure change. (Section U2.03.1) * Unit 3 shif t management and operator performance during infrequent plant evolutions were deliberate, well communicated, and handled with proper consideration of shutdown risk and plant safety. These observations confirm past NRC conclusions regarding conservative decision making by the on-shift crews during special tests and evolutions. One inspector observation of on-shift response to a gradual pressurizer leve,I reduction contrasted with the deliberate and dedicated
, control witnessed this period overall. The inspector discussed with licensee
- management the possible need for increased emphasis on attention to routine Mode 5 activities to preclude similar future occurrences. (U3.03.1) , . *: . Although a sampling review of the Unit 3 implementation status for NUREG-0737, TMI Action Plan Requirements, noted acceptable results overall; incomplete items were identified. These ;tems included,1) the FSAR is not current regarding the TMl iv '
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items,2) there is a discrepancy _ between licensee commitments to have a separate - 1
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shift technical advisor in the control room and licensee _ procedure requirements, and : j L3) there is a question as to the effective use of human factors personnel for- '
: independent and line functions.1(U3.03.1)l -
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Maintenance
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_ j e At Unit 1,' surveillance procedure IC 400A 38, ," Fire Water Tank A & B Level- ;
' Calibration," stated: that "the inia.t valves must be disabled temporarily to preventi
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l the tank from overflowing during calibration. ' To disable the inlet valves, PLACE "N ' -- !
- Fire Water TK Fill" switch to OFF " The technicians performing the test determined _
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that blue tags would be used to control the configuration of the equipment during i the test. The inspector concluded that the use of blue tags for configuratio ,
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, - controli while not prohibited by procedure,' was nonetheless inappropriate and . j ' created an unnecessary challenge to the blue tag system. IC 400A 38'will be ~ " d ,
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revised to specifically control this evolution. (Section U1.M1.1)
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- - ;e? - At Unit 1, the operations staff identified that the special procedure, SP 680P, "Al l L Flow Test of Gas Turbine CO System and Damper Actuation," lacked specific guidance in the procedure, in particular, with regards to the number of compressed ;
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' devices. This test was an example of a longstanding problem that was recognized ,
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by the plant operators'and raised to management's attention for resolution. The l Inspector noted that operations management is continuing to encourage operators to ,
' -identify additional testing issues, where operators need to compensate for t equipment not functioning as designed, in order to have the procedures correcte * (Section U1.M1.2)
J - e' At Unit 2, due to miswiring of a new solenoid valve, the outlet valve for the "C" i ' reactor building closed cooling water (RBCCW) system unexpectedly opened when " power was restored causing the "C" RBCCW pump to trip on low suction pressure y when Facility 2 water was diverted to the partially drained Facility 1 header. Losing e cooling water for approximately 35 minutes led to an increase in spent fuel pool ' temperature of about % *F.- This item was considered unresolved to allow NRC . e t review of the licensee's completed root cause analysis of this event. (Section U2.M1.1) a ' e- - The licensee's complete'd corrective actions regarding Unit 3 LER 96-037, potential _ , l spent fuel poolinoperability, were adsquate.- Installation of a dry box to facilitate , related modifications on the spent fuel pool purification piping was well coordinated
. and controlled. Modification work was appropriately stopped and/or rescheduled to , s accommodate operations, equipment, and procedural issues. (U3.M1.1 and : U3.M8.1), :o: Licensee attention is needed to resolve Generic Letter 8913 items related to heat
- exchanger performance at Unit 3. Open issues inckxie aspects of surveillance and - U
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. . controls to reduce flow blockage due to biofouling and the test program for heat exchanger capability. (U3.M2.1) Engineering
* At Unit 1, the licensee is continuing their efforts to resolve the anomaly identified with an unexpected increase in the emergency diesel generator lubricating oil sump level. This issue will remain unresolved pending further troubleshooting and investigation by the licensee and review of the results by the NRC. (Section U 1.E 1.1) * At Unit 1, the inspector concluded that the weekly engir eering leadership meeting process was an excellent method for manat,ement to raise standards, and to incorporate accountability into the day to-day work activities within the engineering department. The first focus area of the weekly leadership meetings was the 10 CFR 50.59 process. The insoector has noted improvements in the evaluation and screening reviews prepared by engineering. Additional areas will be reviewed at future weekly meeting, for example, the rolea and resporisibilities of the engineering duty officer. (Section U1.E1.2) * At Unit 2. in response to the NRC's Demand for Information pursuant to 10 CFR 50.54(f), the licensee provided the second update to the list of items to be deferred until af ter restart. NRC inspection of the deferred items found that the licensee had improved the review and approval process to provide additional assurance that the list would be complete and accurate. The process resulted in the list containing items that were appropriate for deferra: and overall the contents of the list reflected a conservative decision-making process. The inspectors did not identify any issues that, if not corrected prior to plant restart, would have resulted in a signnicant safety concern during plant operations. (Section U2.E7.1) * At Unit 2, the licensee's corrective actions to identify and correct numerous drawing discrepancies associated with the reactor protection system cabinets, including the linear and wide range nuclear instrument (NI) drawers, were good. The licensees'
decision not to redraw the linear and wide range Ni drawer drawings was acceptable because the drawings can be read, albeit with some difficultly. (Section U2.E1.1)
* The licensee improved their review and approval process for Unit 3 items included in the 10 CFR 50.54(f)-requested list of itemc to be completed after restart to provide additional assurance that the list would be comp!ete and accurate. The process resulted in the listing of items appropriate for deferral and reflected a conservative decision making process. No items were found on the list that, if not completed prior to restart, would have resulted in a significant safety concern during operatio (U3.E1.1) * Corrective actions to address electrical separation noncompliances i , the Unit 3 mnin control room panels and other plant areas were determined to be acceptabl vi
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. . < The licensee has a proactive program to identify and correct electrical separation , noncompliances at Unit 3. (U3.E2.1) Plant Support
* Improvements were noted in the radwaste processing programs at all three units, !
and the radioactive materials transportation and radwaste disposal program continued to be effectively implemented. The technical train lng program for personnel involved in the transportation of radioactive materials was also very effective. One area of weakness was identified in the followup and closeout of issues identified during the April 1997 audit of the radwaste and process control programs (Section IV.R1.1, R5; R7)
* At Unit 2, the licensee failed to create a physical barrier to prevent unauthorized access to a Technical Specification Locked High Radiation Area in the vicinity of the ;
regenerative heat exchanger in the Unit 2 containment building. This was ; characterized as a non-cited violation. (Section IV.R1.2) i
* The inspector reviewed an incident where an individual reported th.:t she had been notified by security when exiting the protected area that she hsd not been properly logged into the protected area in the security computer when she entered. The inspector determined that the individual had not been logged into the protected area because of a mechanical f ailure on the entrance turnst.le when she entered the -
protected area. Further review disclosed that two of eleven turnstiles used to access and egress the protected area had intermittent mechanical failures that resulted in the failure to log authorized personnel entering the protected area (PA).
Only authorized personnel could enter the PA through the defective turnstiles; therefore, no security vulnerability resulted. The turnstiles have been repaired and testod and now operate properly. (Section IV.S8.1) e vii
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$tgDGIAQLQijant Status i t ~ Unit 1 remained in an extended outage for_the duration of the inspection period. The) ]j - licensee continues to' implement configuration management program (CMP) activities, . _
' _ engineering reviews, and docketed correspondence assessments to verify compliance with
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the established design and licensing basis of the unit. The' successful completion of these } activities are required by NRC order prior to restart of the unit. There is a reduction of l restart activities at Unit 1 through the end of this year with a planned restart in the second
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half of next yea U1.1 Operations j i U101 ' Conduct of Operatior s : > i 01.1 n=narmi commenta (717071 l '
' Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing d
plant operations. Proper control room staffing was maintained, access to the control room: , g was properly controlled, and operator decorum was commensurate with the plant , configuration and plant activities in progress. . The operators were attentive in carrying out I their assigned duties and ensured that the control room was free of distractions, with the ' exception of one instance stated below. The' inspectors visually inspected tags on the' L control room panels to determine their age and whether they were consistent with the ! tegout log, as well as how they impacted plant operations, and no discrepancies were identified. Additionally, the irspectors verified operability and availability of the plant * i systems needed to maintain the plant in a Green shutdown risk condition, through direct - observation of associated activities and reviews of surveillances.
d 01.2 Lnna of the "D" Servica Water Pumn 3 Inanaction Senne (717071'
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, The inspector observed the operating shift's response to a loss of the "D" service water ;
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. work orders that were open from the previous SW outsge. Prior to the loss of the "D" SW !
: pump, the gas turbine (GT) generator was out of service for maintenance and Unit 1 was in
- - a Yellow ' shutdown risk conditio .
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f Oh==rvations and Findinom On October 7,1997, the gas turbine was tagged out of service for repairs on the voltage ' regulator. The_."D" SW pomp was started so that the running pump ("C" SW punip) could
; be shutdown for maintenance in the "B" circulating water bay. : Shortly after the pump
'_ start,'a plant equipment operator in the screen house noticed that the "D' SW pump was
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' exhibiting a metallic noise and reported this information to the control room. The Unit - -
. Supervisor went out to the screen house to listen to the pump and recommended that the :
: condition based maintenance (CEM) group be notified. A CBM representative responded to g -
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the screen house to record vibration data on the pump and motor. The CBM representative noted an increase in the " normal spectra" vibration readings, slightly over the Alert rang The CBM representative concluded that the problem may have been the result of a loss of structural stability in the pump shaft support structure. At approximately 4:00 pm, the "A" SW pump was placed in service and the "D" SW pump was shutdown, at the request of the CBM representativ With the "D" SW pump unavailable, the operating crew determined that the emergency diesel generator (EDG) was not available for service. The availability of the EDG to provide power relies solely upon the "D" SW pump, since the pump is powered fram the 4160 Vac Bus 14F, which in turn is powered by the EDG. The operating crew performed a shutdown risk assessment that indicated that the unit was in a Red shutdown risk condition for the
" Ultimate Heat Sink" category due to the unavailab;lity of an emercency power source for both the SW and reactor building closed cooling water pumps. Additionally, the " Power Availability" category of the shutdown risk assessment indicated a'i Orange condition due to the unavailability of both emergency power sources (EDG and GT). It is important to note that normal offsite power was available throughout the even The inspector responded to the control room at 4:15 pm and observed the shift's response to the events. At that time, the plant was in a stable condWn with the EDG tagged out of service, and the "D" SW breaker was open and racked down to prevent further damage to the pump. Numerous individuals were in the control room and a number of discuss!ons were taking place, which were at times very noisy and distracting to the operators. For the next two hours, different groups of people carried on discussions in the control room that were disruptive to the shif t. There was some confusion on the part of plant management as to how or why the plant was in a Red shutdown risk condition as a result of only one inoperable SW pump. The inspector noted that there was a significant amount of discussion as to how to proceed, and there was some difficulty la developing a contingency plan. Discussions lasted for almost two hours before a decision was made on a course of action to restore defense-in-depth for the ultimate heat sink. Even after the contingency plan was determined, there was confusion about how the plan should be documented and who would need to approve it. The final contingency plan included restoring the "D" SW pump and the EDG to an available status (ready for an automatic initiation), while the restoration of the gas turbine (GT) was expedited. The repair and post-maintenance testing of the GT was completed at approximately 10:00 pm, and the unit was returned to an overall Yellow shutdown risk conditio The inspector observed that during the event, command and control within the operations shift was weak, with no clear expectation as to who was responsible for making the appropriate decisions to return the unit to a Yellow condition. Present in the control room during the event was the assistant operation manager (the shift manager at the time); the ope ations manager; the Director, Unit Operations; the technical support manager; and the Director of Maintenance. While there were a number of small group conversations going on, no single management individual focused the activities into a cohesive plan. More appropriately, the requisite contingency planning should have been conducted outside of the control room.
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As a result of the events, the licensee initiated CR M197-2229 to document the unplanned entry into a Red shutdown risk coniition. Operations performed a root cause investigation and determined appropriate corrective actions to address the root'causes of this even The corrective action not only addressed the technical aspects of the event, but also the adequacy of management's response to the event. One of the corrective actions included
- the assignment of a full time shutdown risk coordinator with clearly defined roles and responsibilities. The corrective ections developed from the root cause investigation .
adequately addressed the inspector's concern Conclusion Operations response to an unplanned entry into a Red shutdown risk condition was not well coordinated.- During the event, command and control of the shift was weak and without clear expectations as to who was responsible for making the appropriate decisions to return the unit to a Yellow shutdown risk condition. The issue of command and control within the management of the operations department was identified in an earlier NRC report 97-202, as a problem area. The licensee took steps to ensure that the roles and responsibilities of the recently appointed operations and assistant operation managers, were clearly defined under a new reporting structure. Th" event demonstrates the need for continued management support and direction to 'sure adequate command and control within the operating shift U108 Miscellaneous Operations issues 00.1 (Uodated) Esentated Enforcement item (EEI) 50-245/97-02-01: Failure to Trend Condition Reoorts (CRn): (SIL 17 Update) Inspection Scoon (92901) The inspector reviewed the licensee's corrective actions regarding the failure to trend CRs , in accordance with RP-4, Revision Observations and Findinas RP 4, Revision 2, " Adverse Condition Resolution Program," required a trend analysis to be published monthly, and a CR initiated for any adverse trends identified from this trend - report. In February 1997, the nuclear oversight organization generated CR M1-97-0258, which identified the licensee's failure to perform monthly trend reports since October 1996, < contrary to the requirements of RP-4. The NRC viewed this apparent violation of the RP-4 procedure as another example of the previously identified programmatic breakdown of the licensee's corrective actlon process which was discussed in NRC Inspection Report 96-0 ! As a result, the lice.isee has taken the following corrective actions:
* The Corrective Action Program procedure, RP-4, has been revised te specify a
- quarterly interval for publishing the trend report , .
* " Station Trending Guidelines," SI 100.2, Revision 0, has been established to formalize the trend report methodologies and coding requirement * A trend report was published that provided an analysis for 6ie time period November 1,1996, through January 31,1997. This report bounded the time perioJ in which the licensee had f ailed to issue trend report In addition to the corrective actions listed above, the inspector found that the licensee has published quarterly trend reports within the time requirements established by the current revision to RP- Conclusions The inspector concluded that the licensee had responded adequately to their failure to publish trend reports in accordance with RP-4. However, eel 50-245/97-02-01 remains opon pending completion of NRC enforcement consideration LLLII Maintenance U1 M1 Conduct of Maintenance M 1.1 Fire Water Tank A&B Level Calibratio11 insoection Scone (82707) (SIL 30 Update)
The inspector reviewed the use of the blue tag clecrance process during the performance of instrument and controls (l&C) surveillance procedures. " Tagging"is the process of isolating equipment to prevent the introduction or relecse of energy in order to allow equipment maintenance to be performed safely. A blue-tagged component may only be operated by the designated contact person for that specific tagging reques Observatyns and Findings Surveillance procedure IC 400 A 38, " Fire Water Tank A & B Level Calibration," stated: that "the inlet valves must be disabled temporarily to prevent the tank from overflowing during calibration. To disable the intet valves, PLACE "N-Fire Water TK Fill" switch to OFF." The technicians performing the test on October 14,1997, determined that blue tags would be used to control the configuration of the equipment Juring the test. The blue tags were placed on the "N-Fire Water TK Fill" auto-off-hand control switches for 1-WW-79A&B. This process allowed the technicians to position the switches as needed during the tes The inspector discussed the acceptability of using blue tags for equipment configuration control with the work control supervisor. The supervisor reviewed the issue and determined that the only reason blue tags were being used for this evolution was to maintain configuration control, since there was no procedural controls in place to manipulate the switches, in addition, blue tags were not required by the procedure. The
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inspector concluded that this was not an appropriate use of a tagging clearance, since equipment protection or personnel safety were not a concern during this test. The v/ork control supervisor agreed 6nd sent an E-mail message to the tagging and maintenance supervisors that stated: " Effective immediately, the practice of using clearances :or configuration control during l&C surveillance is stopped, l&C has agreed to develoo procedures to specifically contrni cach evolution." This issue was also discussed at the Unit 1 morning meeting the following day. Additionally, management developed an MP-1 Communications Briefing Sheet titled " Blue Tags." Briefing Sheets contain important information to be comrnunicated to Unit 1 personnel by first lino supersisors in a face-to-face setting. This briefing sheet reviewed the purpose and proper use of blue tags, reiterating the fact that clearances are to be used to protect the health and safety of the workers or to protect plant equipmen As a result of this issue, l&C supervision performed a review of all surveillance procedures (SPs) and ider.tified 21 SPs that required some type of tagging during the performance of the test: nine of 21 SPs required the use of blue tags. A review of those nine SPs indicated that only one procedure required blue tags for personnel safety, and that the other eight SPs would be revised to remove the requirement for blue tags. Until the procedures are changed, they will be placed in a "do not use" status. Additionally,17 procedures, IC 400A, " Calibration of instruments," were identified as requiring tagging on the automated work order (AWO) used to perform and track these procedures, however, the AWOs did not specify which color / type tag to use. Concernir.g tagging, the AWO atsted " determine at time of use," per the tagging procedure and based on plant configuration. Similar to procedure IC 400A-38, blue tagt will no longer be used for configuration control, only for personnel or equipment safet Conclusion Surveillance procedure IC 400A-38, " Fire Water Tank A & B Level Calibration," stated. that
"the inlet valves must be disabled temporarily to prevent the tank frcm overflowing during calibration. To disable the inlet valves, PLACE "N-Fire Water TK Fill" switch tb OFF." The technicians performing the test determined that blue tags would be used to control the configuration of the equipment during the test. The inspector concluded that the use of blue tags for configuration control, while not prohibited by procedure, and thus not a violation, was nonetheless inappropriate and created an unnecessary challenge to the blue tag system. IC 400A 38 will be levised to specifically control this evolutio M1.2 Gas Turbine CO2Svstem Testino Insnection Scone (617261 On October 3,1997, operations performed an 18-month surveillance on the gas turbine (GT) CO2 system using SP 680P, Revision 10. " Air Flow Test of Gas Turbine CO2 System and Damper Actuation." The test used compressed air to simulate a CO2 actuation to ensure proper damper operation and nozzle integrity in the engine and gear reduction compartments. The inspector observed the performance of this test under AWO M1-97-0917 _ . _ _ _ ._ . . . _ . . _ _ _ _- _ .
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, LThe test called for conne'Cng an adapter hose from the east CO, header connection to an d ,
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air bottle.~ The procedure then directed the operator to open the air bottle _ valve and when ~ i
; audible closure of the fire dampers was apparent, close the air bottle valve. Operators ~ l
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encountered problems with the performance of this test a wed. earlier,-when the initial test fusing one air bottle failed to actuate three out of four dampers. The test was performed = second time using two air bottles and subsequently tripped two terbine compartment . d6mpers; however, the turning gear area dampeis failed to close.' At that time, operations -
- wrote a trouble report to document the failed dampers. The test failed a third time -
' ' following corrective maintenance on the dampers by the Fix-It-Now maintenance team. - Following the test failures, the operations staff informed management that there was a lack - , 1of guidance in the procedure, in particular, regarding the number of compressed air bottles ! , . required to ensure enough system flow for actuation of damper trip devices. Uditionally,: .; F ythere was no procedural guidance on the size of the test hose or the specific arrangement
required to accomplish the test. The inspector noted from discussions with operations
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staff that apparently, depending on who performed the test, more than one bottle was l , used and the test was sometimes repeated if the dampers did not actuate'the first tim ine engineering, roaintenance, and operations departments worked together to develop a e new test method that would bet +er_ simulate an' actual CO 2 system actuation with respect to gas pressure and flow rate, in addition, a new test manifold was designed, which consisted of three 750 lb. air bottles, a test pressure gege, and a fast acting ball valv ,
. The ball valve was opened rapidly to simulate the actuation of a normal system discharg ' - Procedure SP 680P was also revised to incorporate the new methodology using the test manifold assembly. The inst.cctor observad the performance of the test using the new Revision 11 to SP 680P. The test was successfully completed with all required dampers -
actuating and all nozzles functioning properly. The test was well controlled and had good management support and coverag .
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2: The operations staff identified that SP 660P. " Air Flow Test of Gas Turbine CO, System
= and Darnper Actuation," lacked specific guidance in the procedure, in particular, with
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' regards to the number of compressed air bottles required to ensure adequate system flow - 'for actuation of damper trip devices. This test was an example of a longstanding problem .
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: that was recognized by the plant operators and raised to management's attention for
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resolutiona The inspector noted that rperations management is continuing to encourage - operators to identify additional testirq issues, where operators need to compensate for equipment not functioning as designed,-in order to have the procedures corrected.
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U1.lli Enginaaring U1 E1 Conduct of Engineering E11 Emcigency_ Diesel Generator tube oil sumo Level Insnection ScoDn (37551) The inspector reviewed the licensee's efforts to resolve an anomaly identified with an unexpected increase in the emergency diesel generator (EDG) lubricating (lube) oil sump level. At the time, the EDG was in a standby mode (not running). Qhsgry.ations and Findings On November 3,1997, plant operators investigated a " Lube Oil Sump High" alarm that was received on the local panel for the EDG. The level was found to be 17/8" above the " full" mark on the "not running" side of the lobe oil sump dipstick. The last recorded sump level on October 14,1997, was 2 3/8" above the " add oil" mark, which is 5/8" below the " full" mark. On November 4,50 gallons of lube oil were removed from the sump, which lowered the level to %" below the " full" mark. Lube oil samples from the engine indicated that the oil was not contaminated with water or fuel oil, and on November 5, the engine was pre- , lubricated and rolled using air. The pre lubrication occurred for approximately eight minutes and resulted in an expected decrease in sump level as the lube oil was returned to the upper area of the engine. Tho 50 gallons of lube oil that were previously removed were subsequently returned to the sump, and the resulting oil fcvel was 1" abevo the " add oil" mar The licensee performed a historical data review, contacted the engine vendor and other owners group members, and conducted troubleshooting. Additionally, operations began taking sump level readings every four hours for trending purposes. On November 7, engineering and operations held a status meeting to determine the basis for acceptability for the discrepant level condition and to review recommended actions. As a result of that meeting, the management team determined that the EDG shculd be run to ensure that there was no problem wi'h the diesel that they were not aware of and to verify the EDG was available for shutdo. n risk consideration. During the meeting, the inspector noted that there was some confusion as to the status of the issue, and there appeared to be some communication problems between the system engineer cad engineering managemen Subsequent to the meeting, the ED0 rurveillance run was successfully completed and an availability determination (AD) was written to document the current condition of the engin The licensee concludsd in the AD that the lube oilissue had no impact on the availability of the EDG to mitigate a cold shutdown Loss of Normal Power (LNP) accident for the following reasons: 1) analysis of *he lube oil showed that the oil wan not contaminated with water nor fuel oil, the analysis also confirmed that the oil was of the correct specification; 2) the engine pre lubrication was performed on November 5,1997, the pre-lubricatlun operation went as anticipated, confirming that the engine was properly
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lubricated; 3) following the pre lubrication, lube oil was ade' d to the engine, the present levelis 1 % to 13/4 inches above the " add oil" level, as raticipated, confirming that the engine ontained adequate lube oil; 4) following the pre lubrication operation, the level increased by between % and 3/4 inches as anticipated and has remained stable since; and 6) data from the previous surveillance indicated that the lube oil pressure was a miiimum of 32 psig as indicated by the engine mounted pressure gauge, which is within the normal specificatio The licensee also concluded in the AD that based on repeated, successful operation of the EDG via the surveillance process and an understanding of the lube oil system, causes for an elevated sump level can be postuisted. For example, an unusually aggressive air roll could evacuate more lube oil fror, the inverted pistons than normal. Since the elevated sump level did not reoccur following the pre lubrication and air roll performed during the troubleshooting, thers is reasonable assurance that the EDG is operating acceptably and therefore, availability is unaf fected, Conclusion , The licensee is continuing their efforts to resolve the anomaly identified with an unexpected increase in the emergency desel generator lubricating oil sump level. This issue will remain unresolved pending further troubleshooting and inves.igation by the licensee and review of the results by the NRC. (URI 245/97 207-01) E1.2 Enoineerina Leadershio Meetina Insoection Scope (375511 The inspector attended an engineering leadership meeting on October 7,1997, for all Unit 1 engineen.,g personnel. Engineering management conducted the meeting to review management expectations and goals, ar., 'o establish a common ground so the department can move forward, Observations and Findinas The purpose of the leadership meeting was to raise the standards of the engineering department, and to foster communications between the design and technical engineering groups. The October 7 meeting also included a review of the activities from the weekly leadership meetings of engineering supervision. The first focus area of the weekly leadership meetings waJ the 10 CFR 50.59 safety evaluation (SE) and screening proces The goal was to provide leadership and education to the engineering department by reviewing completed products that were approved by the department management sponsor. During the weekly meeting, supervisors submit two to three 50.59 evaluations that a o presented by the preparer and the approver. The evaluations are rated and feedback is provided. At the weekly review, the evaluations are approved or returned to the preparer for revision. Lessons learned from the weekly meetings were also reviewed at the October 7 meeting. The meeting also includea a review of safety evaluations, L
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. management's expectations for the 50.59 process, and some recent examples of good j safety evaluation screenings and SE' l l Cond" alan I The inspector concluded that the weekly engineering leadership meeting process was an ; excellent method for management to raise standards, and to incorporate accountability into i the day to day work activities within the engineering department. The first focus area of i the weekly leadership meetings was the 10 CFR 50.59 process. The inspector has noted i improvements in the evaluation and screening reviews prepared by engineering. Additional , areas will be reviewed at future weekly meeting,' for example, the roles and responsibilities
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Rapart Datalia , Rummarv of Unit 2 Etatum Unit 2 entered the inspection period with the core off loaded. The unit was initially 2hw down on February 20,1996, to address containment sump screen concerns, and has
- remained shut down to address an NRC Demand for information 110 CFR 50.54(f)) letter requiring an assertion by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Repor In accordance with commitments made to the NRC regarding corrective action progress and documentation of the completed work items, the licensee has provided a number of corrective action completion packages far NRC review. This inspection report documents closure of a number of issues, reflecting progress in the resolution of open NRC inspection
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'i tems, as well as an Indication of the licensee's program to demonstrate corrective action program effectiveness. A number of items involve modifications or other engineering evaluations that are not yet completed. As an on-going process, the NRC will continue to review available closure packages upon licensee completion of necessary corrective action U2.1 Operaniana U2 01 Conduct of Operations 01.1 nanarmi comments (717071 Using Inspection Procedure 71707, the inspectors conducted frequent r6 views of ongoing plant operations, particularly with respect to shutdown risk management controls. Where ~ appropriate, interviews wee conducted with licensed operators and other support personnel to assess the level of control and knowledge being applied with regard to observed operational evolutions. Overall operator performance during the inspection period corWinued to be good. Changes in plant conditions to support maintenance activities, including the swap in the protected train from Facility *B" to Facility *A", were well controlled and event free. Strong pre-evolution briefings contributed to this good performance. However, section 03.1 of this report opens an unresolved item to allow : further NRC review of a licensee identified concern of whether administrative procedures allowed operators to "N/A" a step in an operating procedure rather than process a procedure change, n
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U2 03 Operations Procedures and Documentation 03.1 Temocrarv_Swnooing of the in. Service Reactor Building Closed Cooling Water Heat Exchanger Without Swagoing Service Water i inspanilonScone (62707) This inspection involved interviews with licensee personnel and reviews of procedurea associated with the September 1.1997, event associated with a temporary swap of the in-ser9e reactor building closed cooling water (RBCCW) heat exchanger, Observations and Findings Prior to this event, Unit 2 was using the "C" RBCCW pump, the "C" RBCCW heat exchanger, and the Facility 2 RBCCW header for cooling plant loads, most notably the spent fuel pool (SFP). On September 1,1997, operators noticed a packing leak on the "C" RBCCW heat exchanger outlet valve (2 RB 4.1E) to the Facility 1 RBCCW header. The Facility 1 RBCCW header hed been drained to support maintenanco and was partially refilled when the packing leak began. The licensee thought the leak could be caused by dry packing and decided to manually cycle valve 2 RB-4.1E to see if this would redace or stop the leakage. In order to cycle this valve, the "C" RBCCW heat exchanger needed to be isolated and the "B" RBCCW heat exchanger needed to be placed in service to maintain sufficient flow rate through the RBCCW syste The evolution to temporarily swap heat exchangers and cycle valve 2 AB-4.1E was discussed at length by the operating crew and the Assistant Operations Manage Procedure OP 2330A, Section 5.2.3, provides instructions for swapping from the "C" RBCCW heat exchanger to the "B" RBCCW heat exchanger. Step 5.2.3.1 instructs operators to refer to procedure OP 2326A, " Service Water System," and establish service water flow to the "B" RBCCW heat exchanger. Operators initially thought that estatlishing service water flow to the *B" RBCCW heat exchanger was undesirable because the shif t turnover report indicated that the "B" RBCCW heat exchanger was "for emergency use only" because a service water tee to this heat exchanger was degra: led due to erosion / corrosion. Operators discussed this concern with Plant Engineering who indicated that this alignment was acceptable for short term operation. After significant discussion
.nd planning for this swap, the operating crew made a decision to not align service water to the "B" RBCCW heat exchanger, even though OP 2330A required it, because they planned to immediately shif t back to the *C" RBCCW heat exchanger. Operators were aware thrit the spent fuel pool would not receive cooling from the ultimate heat sink for the duration of this task, about 10 minutes. The operators believed that a procedure change was not require Cycling valve 2 RB 1.4E was successfulin that the leak was corrected mnd was attributed to dry packing; the swap only lasted about five minutes. SFP temperature was monitored by a second licensed operator and no heatup was noted (the expected SFP heatup rate was less than 1'F per hout and the time to boil the SFP was 139 hours), the operators were prepared to valve-in service water to the "B" RBCCW heat exchanger if necessary,
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i personnel were assigned to locations at the RBCCW heat exchangers, and constant communications were maintained. Despite these contingencies, Unit 2 management asked that a condition report be generated to address the operators' decision to not align service : water to the "B" RBCCW heat exchanger, and whether the operating crew complied with procedure The licensee's preliminary root cause analysis concluded that: (1) No adverse conditions resulted frorn the operators' actions on September 1,1997; The operators thoroughly , prepared for the swap and ensured all activities were adequately discussed, including i system response and contingency actions and; (2) Based on the guidance in DC4,
" Procedural Compliance," a procedure change was not required and the operators were acting within the guidelines of procedure DC4. Procedure DC4, Step 1.6.3, describes the actions that should be taken if a step or sub-step cannot be or should not be performed as a result of plant conditions. Step 1.6.3 allowed omitting a step without a procedure l change af ter consultation with a first line supervisor or Shif t Manager / Unit Supervisor as :
long as omitting the step does not: (1) Change the intended objective of the task or ! evolution as specified by the procedure: (2) Cresta an unsafe plant condition; (3) Violate ; Technical Specifications; or (4) Result in a deviation from a License Basis Document. The licr% q reot cause analysis indicates that procedure DC4 was loosely written in that it ' doet v yWde direction to document the reason why a step or sub-step is being omitted using 6 m udure DC4 guidanc The licensee's reliminary root cause analysis recommended that: (1) This event, including ! lessons learned and recommendations, should be discussed with all operations personnel: ,
(2) Operations personnel should receive training on procedure compliance, procedure ,
changes, the station qualified reviewer process, and the 10 CFR 50.59 process: (3) Operations personnel should receive training on the use of tha final safety analysis report during the uecision making process; and (4) a corrective action plan should be developed to resolve the procedure use process, Conclumlons Not aligning service water to the "B" RBCCW heat exchanger for 5 minutes had minimal safety impact on the plant. However, once engineering told the operators that the degraded service water tee was c.,nsidered safe and that it was acceptable for short term operation, the service water system should have been aligned to the "B" RBCCW heat exchanger. Although the Technical Specifications (TS) and the Final Safety Analysis Report (FSAR) do not specifically prohibit isolation of the ultimate heat sink, operating in this manner did not appear to be justified based on the activity in progress (stroking a valve).
Procedures DC4 and DC1 discuss procedural compliance and administration. An " intent change" modifies the scope of a procedure, the applicability of a procedure, or the basic method or process of task performance. A "one time" change allows a procedure to be modified on a temporary basis to compensate for a plant condition or situation that differs from the conditions and situations the procedure was originally designed to address. An intent change and one time change require all reviews and approvals to be completed prior
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to use, if a procedure change would have been initiated, a 10 CFR 50.59 safety evaluation ;
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may have been required to determine if not providing service water'to the "B" RBCCW heat exchanger would challenge design basis assumptions. Stepping through the safety i evaluation process would have provided assurance that no unreviewed safety questions i would result from tha procedure change. However, since a procedure changs was not : initiated, the safety evaluation was not formally considered. The Inspector found the l _ preliminary root cause analysis to be of good quality, but did not agree with some of its l concluslon l This event will remain unresolved pending issuance of the final root cause analyses by the licensee and subsequent review of them by the NRC. (Unresolved item 50 336/97 207 02) i U2.ll Maintenance
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U2 M1 Conduct of Maintenance j
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M1.1 - Tamnararv Loan of Ranctor Buildina clomad coolina Water
- Inanaction Senna (82707)
This inspection involved interviews with licensee personnel, as well as a review of procedures associated with maintenance activities that led to a loss of the reactor building closed cooling water (RBCCW) system on September 2,1997. (Reference Section 0 above) Ohaarvations and Findinas Prior to this event, Unit 2 was using the "C" RBCCW pump, the "C" RBCCW heat exchanger, and the Facility 2 RBCCW header for cooling plant loads, most notably the spent fuel pool (SFP). The Facility 1 RBCCW header had been drained to support maintenance and was partially refilled. Maintenance workers had recently replaced the ' solenoid on valve 2 RB 4.1E, the "C" RBCCW heat exchanger outlet volve to the Facility 1 RBCCW header. Due to a wiring error by a maintenance electrician, when power was restored to 2 RB 4.1E, it inadvertently opened, causing a cross connect between the Facility 2 and the partially filled Facility 1 RBCCW headers. Since RBCCW flow was l diverted to the partially filled Facility 1 RBCCW header, both the suction and discharge ; pressures decreased, causing the "C" RBCCW pump to trip. The main consequence of losing cooling water for approximately 35 minutes was an increase in spent fuel pool _ temperature of about % 'F. To restore the plant, operators entered abnormal operating _ procedure (AOP) 2564, " Loss of RBCCW," manually closed 2 RB-4.1E, and restarted the
"C" RBCCW pum In June 1996, automated work order (AWO) M2 97 0207 was approved to replace the ai ' operated pilot solenoid on valve 2 RB-4.1E. Since the existing solenoid was being replaced with a different model solenold, replacement item evaluation (RIE) 96 0109 was generated
. to address this situation. Before the solenoid was removed, Attachment 3, " Lifted Lead !
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and Jumper Device Data Sheet," of WC-10, " Jumper, Lif ted Lead and Bypass Control,"
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wa utilized to document two lif ted leads from the solenoid. After the solenoid was removed, it was taken to the maintenance shop so that the lead markings could be applied , to the new solenold. Since the solenoids were physically different, the electrician t incorrectly transposed the lead markings to the new solenoid. The solenoid was installed ' using Attachment 3, so that when power was restored to the valve, a close signal (due to the hand switch being in the close position) caused it to ope , The licensee's preliminary root cause analysis of the event determined that the applicability of WC 10 for temporary or permanent modifications is not well understood by maintenance personnel. If the engineer who wrote the work package for the solenoid replacement job would have recognized the limitations of WC 10, an alternate means to ensure 1
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configuration control could have been included as an attachment to the work packag Other f actors contributing to the event were the electrician relied on valve orientation to identify lead markings, failed to review design information within the work package, failed to request a second verification of the lead markings on the replacement solenold, and failed to notify supervision that Attachment 3 did not address new were markings on the replacement solenold. Recommended corrective actions for this event included: 1) Maintenance Department personnel should receive additional training on the use of WC 10 Attachment 3 in applications for the repair and replacement of equivalent components; 2) the Maintenance Department should perform a self assessment to evaluate personnel errors ; due to a lack of self checking; and 3) consider a change to WC 10 or develop a new procedure to address repair and replacement of equivalent component '
, Conclusions Loss of the RBCCW system on September 2,1997 had minimalimpact on ths plant in that spent fuel pool temperature increased by about % 'F in 35 minutes. Although the engineer that developed the work package could have provided better instruction concerning lead markings on the new solenoid, the maintenance electrician should have stopped work and questioned supervision when he reallred that he did not have clear instructions on how the ;
lead markings should be transposed to the new solenoid. The inspector found the ! preliminary root cause analysis to be of good quality except that it was somewhat narrowly ; focused in that it failed to address the operational aspects of this event. For example, the preliminary root cause analysis could have discussed the significance of testing valve 2 RB-4.1E while its RBCCW loop was in service, or other alternatives prior to placing the valve ' back in service. For example, the operat;ons department could have isolated the "C" RBCCW heat exchanger and used the "B" RBCCW heat exchanger, or delayed placing valve 2 RB 4.1E back in service until the Facility 1 RBCCW header was filled and vented so that the "A" RBCCW heat exchanger could have been used. If the "C" RBCCW heat exchanger was isolated, this event could have been avoided. This event will remain unresolved
- (Unresolved item 50 336/97 207 03) pending issuance of the final root cause analysis by the licensee and subsequent review by the NR ,
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M1.2 Shutdown Cooling Heat Exchanger Maintenance Insoection Scone 162707) (SIL 6 UPDATE) The inspectors observed the performance of Automated Work Order (AWO) M2 97 03174, ""B" Shutdown Cooling Heat Exchanger Machining of Shell Head." The inspection activities included discuss!ons with maintenance technicians and a review of AWO and work boundarie Observations and Findings The perfctmance of maintenance technicians was good. During this observation, the workers were measuring the deviation of the heat exchanger shell and head seating surf aces from plane to determine necessary machining to return the seating surf aces within design specifications. The workers demonstrated appropriate awareness of ALARA principles by selecting work locations in lower dose areas when practica The AWO contained appropriate documentat:on authorizing the work and defining the scope of work. Calibration records for the measurement equipment were included with the AW The inspectors reviewted the work boundaries by comparing the tagging record to the piping and instrumentation drawings for the affected systems. The work boundaries effectively isolated the *B" shutdown cooling heat exchanger, Conclusions Overall, conduct of the "B" shutdown cooling heat exchanger maintenance was goo U2 M3 Maintenance Procedures and Documentation M3.1 Igggina of Discharge Path During the Llould Radiation Monitor Surveillance insot.ction Scope 171707) (SIL 6 UPDATE) The inspector evaluated the appropriateness of Revision 2, Change 3, to procedure SP 2404AA, " Aerated Liquid Radiation Waste Process Radiation Monitor RM 9116 Functional Test," and Revision 2, Change 5 to procedure SP 2404AC, " Clean Liquid Radiation Waste Process Radiation Monitor RM-9049 Functional Tert." The procedures were changed to utilire procedural controls rather than danger tags to ensure that the manual effluent discharge isolation valves (2 LRA 125/126 and 2-LRR 127/321/322) are closed to prevent a discharge from the Aernted Waste Monitor Tank (AWMT) and Clean Waste Monitor Tanks (CWMTs) to Long Island Soun _ . _.- o e 16 Observations and Findings Radiation Monitors RM 9116 and RM 9049 are designed to monitor radiation levels in the batch discharges from the AWMT and CWMTs to Long Island Sound and to automatically isolate the discharpe flow path using the effluent trip valves if the radiation level reaches the established apoint. Procedures SP 2404AA and SP 2404AC are performed to test the alarm and trip functions associated with the radiation monitors which requires opening the associated automatic trip valves several times, in an effort by Operations to reduce unnecessary tagging, Procedures SP 2404AA and SP 2404AC were changed to have a plant equipment operator (PEO) verify that the associated manual effluent discharge isolation valves are closed but to no longer require that tha valves be danger tagged close To further reduce the likelihood of an inadvertent discharge, procedure SP 2404AA was changed in Revision 2, Change 4, to add a step that verifies that either: (1) the AWMT is not being recirculated, or (2) the recirculation pump discharge valve is closed, which allows recirculation while isolating the effluent flow path. A discharge can only occur if the AWMT pump la running due to elevation differences between the AWMT and the piping outf all. A similar change is planned for SP 2404AC prior to the next performance of this surveillanc To evaluate the procedure changes, the inspector reviewed the regulatory requirements associated with tagging including 29 CFR 1910.147, "The Control of Hazardous Energy (Lockout /Tagout)," as well as the licensee's implementing procedure WC 2, " Tagging."
Danger tags are required to be installed to support the servicing and maintenance of machines and equipment in which the unexpected energiration or startup of the machines or equipment or release of stored energy could cause injury to employees or could damage equipment. Because reducing the possibility of an inadvertent discharge does not involve injuries to employees or equipment damage, regulations do not require danger tagging the manual of fluent discharge isolation valve Although the danger tags in this cast, are not required by regulations, the inspector evaluated whether it would be appropriate to hang them anyway as an additional preventive measure. The Plant Operation Review Committee (PORC) approved the changes to procedure SP 2404AA because having the PEO verify the valves are closed and verifying that the AWMT and CWMTs are not being recirculated (or by closing the recirculation pumps' discharge valve) provides two barriers that must both be overlooked to result in an inadvertent discharge. The NRC found that PORC approval of the procedure changes to be acceptable. The valves that are verified closed are the same valves that were previously danger tagged closed. Procedural steps, rather than danger tags, is the normal method used by operators for controlling plant configuratio Conclusions The NRC determined that the changes to procedures SP 2404AA and SP 2404AC to no longer require danger tags on the manual effluent discharge isolation valves were acceptabl . .
U2 M8 Miscellaneous Maintenance issues M8.1 (Closed) Ucensee Event Reoort 50-336/96-41! Fuel Transfer Tube Flange Test Port Blocknoe Insoection Scone (92RQ31 The inspectors reviewed the corrective actions taken by the licensee to address a problem where a localleak rate test port was inadvertently blocked during assembly of a blind flange, Observations and Findings in December 1996, during removal of a blind flange from the fuel transfer tube, the , licensee discovered that the localleak rate test port was plugged with a silicon rubber seslant compound. The test port connects to the area between two 0 rings that are used to provide a seat betwesn the blind flange and the transfer tube. The sealant was used to hold the 0 rings in place during the previous installation of the blind flange. The flange installation was controll:,d by a work order and there were no specific directions on the use of the sealant or cautions relative to the potential for plugging the test por Th1 licensee issued maintenance procedure MP 2704S3, " Fuel Transfer Tube Blank Flange Pomoval and Installation," on February 7,1997, to provide specific guidance and precautions to the maintenance mechanics to prevent recurrence of a similar even Training was also provided to maintenance personnel to emphasize attention to detail during work related to localleak rate testing activitie Conclusions The inspector reviewed the licensee event report (LER), the associated adverse condition report and the maintenance procedure and concluded that the licensee had implemented appropriate corrective actions. LER 50 336/96-41 is close M8.2 (Onen) eel 50-336/97 02-12t Inadeounte Suryfiitance Test Procedures (Undate - Significant items List No. 8) Insoection Scone (92902) Based on 17 LERs discussed in Inspection Report 97-02 and previously identified NRC violaticas concerning surveillance test procedure deficiencies, escalated enforcement action was proposed for repetitive technicalinadequacies in surveillance test procedures. The inspector reviewed administrative procedure changes and other corrective actions taken by the licensee to ensure all Unit 2 surveillance test procedures will be technically adequat _
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Procedure DC-3, " Verification, Validation, and Approval of Procedures and Forms," Revision 2, dated September 3,1997, has been revised to improve the technical review process for new and modified procedures. A review is now required by one or more of the
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engineering groups if a new procedure is being developed or an existing document is being modified if certain criteria, as defined bv procedure DC 3, are met. The engineering review i
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requires, in part, that procedures accurately address NRC regulations, enders, license conditions, exemptions and technical specifications, in addition, there is a required independent review which verifies the completeness and technical accuracy of the i procedure. Nuclear Group Procedure 3.12, " Safety Evaluations," Revision 10, dated March l 1,1997, strengthens the safety evaluation prncess (50.59 review) and ensures that the i procedure conforms to the final safety analysis repor i Although the procedure upgrade program (PUP) is nearly complete, the nicensee is re- l reviewing all Unit 2 surveillance test procedures for technical adequacy. Part of this is being done by' the configuration management program (CMP) for selected systems and the remainder is being accomp!!shed by a system engineer review. These reviews are to en9ure technical adequacy, and deficiencies are identified by writing a condition report (CR). The reviews for surveillance tests required for entry into Modes 5 and 6 have been completed; however, su.veillance tests required for entry into Mode 4 and above are still under review. The CRs are identified by mode requirement and can be placed in the licensee " punch list" documents as to what is required (or each mode change including restart. A separate procedure group will make the corrections. A sample of CRs written for the Mode 5 and 6 reviews, were reviewed by the inspector. It appears that a number of technical deficiencies hLve been identified for corrective actio Conclusions The ongoing process appears to be effective in L!entifying technical issues not previously identified during the PUP. This item remains open pending completion of licensee review Actual correction of the procedure is not required for closure as the corrective action
. process will track procedures @at are required for applicable mode changes as equipment must be within required surveillance to enter a higher mode. eel 50-336/97-0212 remains open pending lic,casee comp'etion of Unit 2 surveillance test review U2.lil Engineadna U2 E1 Conduct of Engineering E Wida. Range Nuclear instrument Drawing Insanction Scone (37551)
The inspector evaluated the licensee's disposition of Adverse Condition Report 'ACR) 013461 which was initiated by the licensee on May 17,1996. Thie ACR described that an Instrumentation and Controls (l&C) technician found that the drawings for reactor i _
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19 l protection system (RPS) cabinets SA,58, SC, and SD did not match the actual plant configuration wiring and did not reflect old modifications. Thi neluded the linear and wide range nuclear instrument (NI) drawers and external cabinet wiri.ig, Obmarvations and Findings The inspector discussed this ACR with the I&C technician who initiated the ACR. He stated that he reviewed the drawings for accuracy to support a possible future modification to replace the wide range drawers. The l&C technician stated that the wide range NI drawers were a particular area of focus, and that his walkdown was detailed. The number of drawing discrepancies, as well as the level of detail associated with the drawing l discrepancies, supports the l&C technicians' assertion that the walkdown was comprehensive. Design Change Notice (DCN) DM2 00 0083-97 was initiated to correct the identified discrepancies associated with Drawings 31083 39069 sheet 8,31084- i 39069 sheet 9,31085 39069 sheet 10,31086 39069 sheet 11, and 25203 29198 . sheets 1 and 3. The inspector verified that the drawing changes associated with this DCN have been complete When reviewing the drawing changes, the inspector noted that Drawings 25203 29198 sheets 1 and 3, of the linear and wide range NI channels were difficult to read due to f ading of the lines and fattening of the typed print. This problem is normally caused when drawings are reproduced over and over to incorporate changes. However, in this case, the licensee stated that the first drawing provided to the licensee in the early 1970's was of poor quality. The licensee considered redrawing these drawings but decided not to because this detailed wiring diagram is used very infrequently, in addition, the licensee is considering replacing the linear and wide tant,e NI drawers due to difficulty in obtsining replacement parts and new drawings we.,uld be provided with the new drawer Conclusions The NRC determined that the licensee's corrective actions to identify and coirect numerous drawing discrepancies associated with RPS cabinets SA SD, including the linear and wide range Ni drawers, were good. The licensees' decision not to redraw the linear and wide range Ni drawer drawings was understandable because the drawings can be read, albeit with some difficultl U2 E7 Qudity Assurant,a in Engineering Activ!tles E Review of items to bet.Comolated Af ter Restart (Undate - Sionificant items List N Inanaction Scone (375501 in a letter dated April 16,1997, the NRC requested, in part, that the licensee provide the following infor_mation pursuant to 10 CFR 50.54(f):
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* For each unit, the list of significant items that are needed to be accomplished prior to restart-
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* For each unit, the list of items to be deferred until af ter restart; and, e For each unit, the process and rationale used to defer items until af ter restar !
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The letter also requested updates approximately every 45 days for the first two items. On [ October 21,1997, the licensee provided the second update to the list of Unit 2 Items to be ; deferred until af ter restar The inspectors reviewed the information provided for Unit 2 to assess: the content of the I list, whether 'he deferrals were apropriate, and that they met the criteria for deferral as stated in the licensee letter of May 29,199 Qhastvations and Findinna , Approximately 1150 items were included in the deferred issues list for Unit 2. The ! Inspectors reviewed the one line description of all of the items and selected approximately l
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125 for a more detailed review. In selecting the items for further review, inspectors considered the safety significance of the systems and the potential for system nnerability to be affected, based on the one line description. The inspectors reviewed supporting i documentation for these items and, for selected items, discussed the issues with the ' licensee staff to obtain sufficient information on each of the items to determine if deferring the item was appropriat The inspectors found that the decision makiria process for deferring items was , conservative and the items on the deferred issues list would not affect safe plant operation. The licensee was generally able to provide a good basis for including the items on the deferred issues list. Some minor problems with the deferred issues list are discussed belo . i
During the process of obtaining additionalinformation requested by the inspectors, the licensee identified several errors associated with items on the list. Condition reports (CRs) were written to document the problems. The inspectors reviewed the issues and determined that the errors were administrative in nature and would no* have resulted in any significant condition being inappropriately deferred. For example, the hard copies of two work orders indicated that the work was to be performed prior to startup, however the work order numbers were inadvertently included on the deferred items lis > As a result of the inspectors' review, the status of two additionalitems were revised. One item that was on the list was already scheduled for repair prior to restart and the other involved updating calculations associated with the spent fuel pool. Again, the inspectors found that these items would not have resulted in a significant safety concern if they had not been resolved prior to restart, However, the items did meet the !icensee criteria for items to be completed prior to restar , __ . _ . _ _ __- _ ___.__ _. _ _ _ _
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The inspectors also noted that the licensee's process for developing the list has been improved to addr ss completeness and accuracy issues that were identified during a previous NRC review of the Unit 3 deferred issues list (NhC Inspection Report 50 423/97-202). For example, in addition to increased involvement of th( t.uclear oversight department, Unit 2 included a line by-line review of the items on the list by the Plant Operations Review Committee (PORC) as part of the review and approval process, Conclusions The inspectors concluded that the licensee had improved the review and approval process to provide additional assurance that the list would be complete and occurate. The process resulted in the list containing items that were appropriate for deferral and overall the contents of the list reflected a conservative decision making process. The inspectors did not identify any is;,ues that, if not corrected prior to plant restart, would have resulted in a significant safety concern during plant operation U2 E8 Miscellaneous Engineering lasues E JClosed) Violation bO-330/94-20102n. 02b and 02c: Three Examoles of Deficiencies in the imolementation of the Plant Design Change Process lDsoection Scone (92903) The inspector reviewed the corrective actions taken by the licensee corecirning the subject violation. The review included interviews with design engineers and operations personnel and a review of applicable procedures and documentatio Observations and Findings Example 94 20102n stated that Plant Design Change Record (PDCR) 2 06191, " Steam Replacement Project Wide Range Level Instrumentation" was closed on November 30, 1993, without incorporating the level instrumentation snhancement into the emergency operating procedures in accordance with procedure NEO 3.03, " Plant Design Change Records." Since this violation was issued, procedure NEO 3.03 has been cancmed by the licensee and replaced with a more comprehensive Dcsign Control Manual (DCM) which is currently at Revision 6. The DCM " Engineering Release Transmittal" form requires that procedure changes and new procedures required by the design change are issued before the release of the PDCR. In addition, EOPs 2537, " Loss of All Feedwater" and 2540D,
" Functional Recovery of Heat Removal" were subsequently revised to incorporate the wide range level instrumentation in the diagnosis procedur Example 94 201-02b stated that PDOR 2 078 92, " Reactor Protection System Pressurizer Pressure Alarm Modification - Power Operated Relief Valve Actuation Logic Reversal,"
Revision 1, was closed prior to performing the verifications of three Design Change Notices (DCNs) that documented the logic, schematic and wiring diagrams as required by procedure NEO 3.03 and procedure NEO 5.11, " Design Change Notices for Design Documents." A review of the DCN cover sheets indicated that the DCN verifications were subsequently
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performed af ter the PDCR was closed. The license stated in its response that the violation was due to poor communications since both corporate and site engineering were involved in the performance of the PDCR. Since the violation was issued, the licem,ee's engineering department has been reorganized and all design changes are now performed at the site. As noted above, the DCM has been issued and has replaced several previous procedures relating to design control. The DCM " Turnover Transmittal" form requires that DCN installation be verified prior to completion of the PDCR packag Example 94 20103a stated that the short form PDCR method was incorrectly used for two PDCRs. PDCR 2-029 93, "Feedwater Motor Operated Valve Actuator Braka Removal," contained six DCN changes to limit switch setpoints, modification of stem nuts, reinforcement of valve yokes, two calculations, and drawing changes. PDCR 2 063 92,
" Engineered Safeguards Actuation System (ESAS) Module Upgrade," replaced ESAS logic modules with new modules using different key operatir.g parameters. According to procedure NEO 3.03, short form PDCRs should only be used for limited design changes requiring limited engineering evaluations. For PCDR 2 029 93, the NRC was concerned that a short form PCDR was used even though a number of additional evaluations and an independent review resulted in reviews equivalent to that of a long form PCD As corrective actions for violation 94 20103a, the DCM has eliminated the short form PDCR. As a result of noise problems encountered following performance of PDCR 2-063-92, a long form PDCR, 2-026 93 was implemented which installed contact noise readers and modified the sequencer modules to eliminate the noise problem Conclusions Based on the above, licensee corrective actions concerning Violetion 50-336/94 201 02 are acceptable and this item is closed. Other examples of this violation that pertain to Unit 2 were previously closed in NRC Inspection Reports 50 336/95 31 and 50 336/96 0 Although the licensee has adequately addressed the concerns associated with this specific violation, the f ailure of the licensee to adequately implement the design control process is one of the primary reasons for the current shutdown of Unit E8.2 (Closed) Unresolved item 50 338/96-08 14: Removal of Stcrton Rate Trio (Closed -
Significant items Ust No. 43) Unrvsolved item 50 336/96 08 14, was created to track the licensee's disposition of Licensee Event Report (LER) 50 336/96 29 which concerned the inappropriate removal of the startup rate trip in 1978. An NRC letter to the licensee dated August 19,1997, states that as a followup action to LER 50-336/96 29, the NRC staff reviewed Siemens Power Cotporation's revised analysis of the control element assembly withdrawal event from low power and the results of this review confirms that operation of Millstone Unit 2 without the startup rate trip continues to be acceptable. Based on this, Unresolved item 50-336/96 0814 and Unit 2 Significant items List No. 43 are considered close _ - - - -
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E8.3 LUndaind) eel 50 33G/96 20129 and eel 50-423/96 201 29: Trendino and Dioritiration of Non-Conformance Reoorts IfClosed) Unit 2 SIL No. 32: (UpdatedL Unit 3 SIL ltem No. 371 Insoection ScQRn_192903} The inspector reviewed the licensee's corrective actions associated with Escalated Enforcement item (eel) 50-336/96 201 29 and eel 50 423/96 201 29. This item was partially closed in NRC Combined Inspection Report (IR) 50 245/97 02; 50 336/97 02; 423/97 02. A review of the associated administrative procedures was performed to encure remaining actions had been completed. Although NRC 1R 97-02 references only the Unit 2 eel 50-336/96 20129, Unit 3 eel M 423/96 20129 was opened to addrese the same concern associated with this site W.Je process, ObMLYAtions and Findings NRC IR 97 02 noted that most actions concerning trending and prioritization of non-conformance reports (NCRs) had been completed, and processes had been established by the licensee. The conclusion in NRC IR 97 02 stated that eel 96 20129 remains open because procedure RP 4, " Corrective Actions Program," had not yet been changed to proceduralire the practice of generating an adverse condition report as a means of tracking NCR The inspector reviewed the most recent revision to procedure RP 4, dated September 5, 1997, and noted that NCRs are not specifically addressed. Instead, the licensee issued Revision 10 to procedure NGP 3.05, "Non-Conformance Reports," dated August 20,1997, to specify that a condition report (CR) be initiated for each NCR generated. This allows evaluation for generic issues and reportability, trending and traceability. The non-conformance report form now provides for entering a CR number to provide an NCR/CR cross referenc Conclusions The NRC reviewed eel 50 336/96 20129 and eel 50-423/96 201 29 and found the licensee's corrective actions to be acceptable. Based on this, Unit 2 Significant items List (SIL) ltem No. 32 la considered closed. Unit 3 SIL No. 37 is considered updated because other items referenced in this SIL item remain open. The violation associated with Eels 50-336/96 20129 and 50-423/96 20129 was issued by the NRC on December 10,1997, and these Eels remain open pending NRC review of the licensee's violation response, i
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flaport Details ; Summarv of Unit 3 Status i Unit 3 remained in cold shutdown (Mode 5) status throughout the inspection period. The . licensee continued to implement unit recovery activities, to include the support of the independent Corrective Action Verification Prograra (ICAVP) inspection activities, field work to physically prepare the plant for mode change / restart, and internal assessments to provide continuing evaluation of the configuration management program (CMP), as well as * licensee program readiness for NRC operational readiness and confirmatory team inspection During the period from November 10 21, 1997, an NRC team reviewed licenses change process controls during an on site inspection, conducted in accordance with the NRC plan for oversight of ICAVP Tier 3 review activities. This inspection will continue with a review * of Sargent and Lundy Tier 3 evaluation progress and will be documented in NRC inspection report (IR) 50 423/97 209. An en-site inspection of the ICAVP Tier 2 accident mitigation i
- systems at Unit 3 by the same NRC team commenced on December 1,1997. A publicly observable management exit meeting for NRC discussion of the Tier 2 and 3 inspection findings with the ilcensee is scheduled for January 199 '
On November 17,1997, the Vice President Nuclear Oversight announced several new Oversight assignments, noming new personnel to fill two of the three Director positions with several new managers reporting to them. On November 24,1997, the Northeast Nuclear President and Chief Executive Officer Bruce Kenyon announced several other senior management changes, including the oeparture of the Millstone Station Chief Nuclear Officer (CNO), Neil S. Carns, effective December 1,1997. Mr. Kenyon assumed the roles and responsibilities of the Millstone CNO and named Mr. Brothers, the Unit 3 Vice President (Recovery Officer), as the Vice President of Operations. Mr. McElwain, the Unit 1 Recovery Officer, takes on the additional responsibility of acting Unit 3 Recovery Officer, reporting to Mr. Brothers. Mr. Bowling, the Unit 2 Recovery Officer, retains that position, but also has the station licensing organization report to him under the announced reorganization. Based upon Mr. Carns's departure, the personnel and other organizations reporting to the CNO have been organizationally realigned under the new VP of Operations and the Recovery Officer . U3.1 Onorations U3 01 - Conduct of Operations-01.1 Ganaral comments (717011 Using inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant operations, including observations of operator evolutiols in the control room; walkdowns of the main control boards; inspections tours w; thin the unit radiologically controlled area and other buildings housing safety-related equipment; attendance at several maintenance planning, plan-of-the-day, and plant opera. ions review committee (PORC)
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meetings; and observations of various management oversight, engineering review and CMP activities, including both field work and licensee decision-making processe Specifically, the inspector observed operational protocol, procedural adherence, and the control of shutdown risk during portions of the following evolutions:
* Volume Control Tank outage and relevant charging flow path and inventory controls * Reactor Coolant System (RCS) Sweep and Vent, conducted in accordance with general operating procedure OP 3218 (Revision 6) * Reactor Plant Component Cooling Water Train B Flow Test, cor: ducted in accordance with special procedure SPROC 97-3 20 * Temporary Modification 3-97 078 engineering evaluation, authorization, and controls * Temporary Modification 3 97-072 safety evaluation for restnration of an operable boration flow path The inspector witnessed shift briefings and turnover activities related to some of the above evolutions. Procedure " prerequisites" were sampled and verified complete prior to the implementation of the operating instructions. The inspector noted appropriate attention to procedural precautions and proper control of the ongoing operations and equipment manipulations. In the case of the RCS sweep and vent, which took place over several shif ts, conservative decisions on the part of the shift managers to suspend the evolution on two separate occasions were noted, and deliberate restart of the procedural steps was confirmed by the inspecto One of the reasons the conduct of OP 3218 was temporarily halted was to evaluatsi the impact of the apparent inoperability of the Train "A" emergency diesel generator (EDG).
While this problem was handled correctly with respect to the ongoing evolution, other operational concerns were identified with regard to the control of bypass jurnpers (BJs) 97-049 and 97-060, both of which affected the subject EDG's capability to withstand design basis conditions. During this time period, the NRC team reviewing ICAVP Tier 3 activities was onsite conducting an inspection of licensee modification controls, including those in place with respect to the EDG enclosure ventilation, as implemented by BJs 97-049 and 97 060. Further followup of the problems encountered by the licensee and the associated NRC inspection concerns will be documented in the NRC inspection team report, 50-423/97 20 Overall, licensee shift management and operator crew performance during the conduct of the evolutions, specist procedures, and temporary modifications listed above, was observed by the inspector to be deliberate, well communicated, and handled with the proper cons;deration of shutdown risk and plant safety. These observations confirm past NRC
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26 l l conclusions regarding conservative decision making by the on shif t crews during the I implementation of special tests and evolution However, during a routine control room board walkdown, the inspector noted a decreasing l ' prer.surizer level trend displayed on a CRT. When discussed with the reactor operator (RO), l he was not aware of the tenson for the trend. Upon further investigation, the operators determined the cause to be a letdown / charging mismatch. Af ter operators balanced the letdown and charging system, pressurizer level stabilized at 82.5 percent inspector review i , of pie.nt computer data confirmed a one percent pressurizer level decrease, from 83.3 to ; ' 82.3 percent, in approximately 2 hours. During this period, pressurizer level was controlled ! within the administrative band of 80 to 90 percen i While no advert,e safety impact resulted from the noted one percent pressurizer level l decrease, this routine control room observation contrasted with the deliberate and l dedicated operations controls that had been witnessed with respect to special evolution ! The inspector discussed with licensee management the possible need for an increased emphasis upon attention to routine Mode 5 activities, where an acknowledged routine lack of operational challenges may lead to decreased sensitivity on the part of the shif t crews, U3 03 Operations Pr: <dures and Documentation > 03.1 Onerations and Overnight Program Review (40500) During this inspection period, the inspector reviewed the status of certain licenses programs, procedures, and assessment activities that had been previously raised as corrective action or operations planning topics of NRC interest. The inspector observed meetings, reviewed licensee progress reports, and discussed with the cognizant issue managers both the results of the ongoing effectiveness reviews and plans for further analysis and evaluation. Among the programs examined for evidence of proper licensee control, criteria, and management attention were the following: "
* Corrective Action Effectiveness Review Team (CAERT) with team report issued October 30,1997 * Millstone Unit 3 Corrective Action Trend Report - 3rd Quarter 1997, issued on October 30,1997 * Unit 3 CMP Design Deficiency Reports (DDRs) Review with conclusions ;
documented in memorandum MP3 DE 971568, dated November 26,1997
* Unit 3 CMP Plan, " Mode Changes - Mode 5 through Mode 1" approved for use by the Station Operation Review Committee on November 26,1997 i *- Nuclear Oversight Rectert Verification Plan (NORVP) Key issues Status - -
Millstone Unit 3, with bi weekly progress reports i e' Nuclear Oversight Monthly Report November 1997
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The inspector noted that the licensee's corrective action trend analysis identified the continued need for improvement in corrective action implementation, operating experience r6 view, and backlog reduction. The Neclear Oversight assessment for the month of November validated the concern that work backlogs continue to represent an impediment to long term station improvement. With respect to CAERT activities, the inspector determined that about half the problem condition reports (CRs) were found to have less than adaquate corrective action plans, with the other discrepancies being of an administrative nature. The Nuclear Safety Assessment Board (NSAB) has shown an interest in the CAERT findings, particularly with respect to operating experience, as well as in the DDR review and analysi The inspector found that the licensee's plan to clearly specify those CMP activities that were required to be performed in support of the Unit 3 mode changes was a deliberate outline and a Good initiative. The scope of the plan included licensee review of CMP discovery efforts at both Units 1 and 2 as well, to assure that the Unit 3 mode changes are acceptabb to the entire station. The NORVP bi weekly status reports also represent a good initiative and ind:cator of progress with respect to both Unit 3 physical plant readiness and programmatic preparedness for planned NRC team inspections. Through the end of this inspection period, about one third of the assessment attributes represented satisfactory areas, not needing further demonstration of improvemen Overall, licensse efforts to asnss, plan, and improve performance in the areas represented by the above listed programs and procedures have been viewed as positive initiatives. As indicated by current results, these otrorts continue and must be sustained since success has not yet boon demonstrate U3 07 Quality Assurance in Operations 07.1 Review of NUREG-0737. TMl_ Action Plan Renuirements.1Undate - Sikitern.38) The licensea performed a detailed review of the current implementation status of each NUREG-0737, TMl item, as documented in Engineering Report, ME ERP 970013, Rev. O, 10/6/97. This review found that Unit 3 was in compliance with 49 of t' 56 items. CRs were written for the other 7 items that required actions to bring the unit into complianc Some of the other items also had ancillary issues noted that may need some action. These are addressed in one summary CR, M3-97 3439. However, the inspector noted some ancillary issues that were not clearly covered in CR M3 97 343 The inspector noted in general that tha FSAR is not completely up to-date with respect to the TMIitems. This includes both Table 1.10-1 and a number of the referenced FSAR sections. The licensee stated that the " Position" column of Table 1.10-1 would be for historicalinformation and they would so note in the FSAR. They also stated that the
"FSAR Reference" column and the specific referenced FSAR sections would be updated to reflect the current status of each TMIite Based upon the inspection findings and comments for each TMl Action Plan item documented below, and pending continued review of the licensee's actions to address and
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complete all the applicable NUREG 0737 issues, SIL ltem 38 remains open and is hereby updated, l.A.1.1 Shif t Technical Advisor (SIAL This item is to provide an on shift technical advisor to the shif t superviso The licensee has established an STA training program, NTM 7.081, and has defined the STA responsibilities in COP 200.7. TS Table 6.21, Minimum Shift Crew Composition, which requires an STA in Modes 1 through 4, but allows the position to be filled by an on-shif t SRO. However, the licensee committed (NU letter B15246 in response to Violation 423/95 07-08) to the NRC to eliminate the use of the dual role STA by the end of 199 This commitment was also noted by the NRC in their closure of this violation in IR 50-423/95 25. Current site procedures do not specify a separate STA as committed. Also, COP 200,1, states under Shif t Manager responsibilities, "If qualified, act as a Shif t Technical Adviror." OP 32r0, conduct of Operations, quotes the TS Table that permits the dual role STA, but notes that the STA and Shif t Manager are "normally" filled by two separate individuals. This item remains open pending revision of procedures or revision of the commitmen LA.1.2 Shif t Supervisor Administrative Dutica This item requires that the Shif t Supervisor not have non-safety administrative dutie FSAR Section 13.12.2.1.4A.k states that administrative functions that detract from management responsibility for assuring safe operation of the plant are delegated to other operational personnel not on duty in the control room. Administrative procedures were reviewed and do not contain the prohibited types of duties for the Shif t Manager (SM) or the Unit Supervisors (US). This area was discussed with a SM and a US, who both stated that plant management has been proactive in this area and that their distracting administrative duties have been kept to a minimum and are now reasonable. This item is acceptabl l.A.1.3 Shif t Mannino This item defines shif t staffing for normal operation and overtime restrictions. The NRC issued Generic Letter (GL) 8212, with updated overtime restrictions, that superseded those given in NU9EG-0737, item I.A. . Shif t staffing requirements for normal operations, consistent with this item, are specified in TS 6.2.2 and Table 6.21. TS 6.2.2.g and Procedure NGP 1.09 contains overtime restrictions that match those of NRC Generic 1.u.ter 82-12. The GL also recommended that licensed operators at the controls be periodb ily relieved ed assigned to other duties away from the control board. Discussions with the Opera *% 'snager indicated that normal practice is to rotate the operator "at the cont ols" fo, agiu .ime to the BOP panel during their shif t. This was also discussed with coritrol room personnel and practices appear to reasonably meet the intent of this recommendatio _
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1.A.2.1 Ungrade of RO and SRO Training and Qualifications This item related to upgrading the qualifications of candidates for ROs and SROs. There are two paths for SRO, either through operations as an RO or from engineering, possessing an engineering bachelors degree. Requirements are given in this item for both case The licensee has defined the training process in their Nuclear Training Manual, including prerequisites, curriculae, examinations, etc. These procedures address initial, upgrade (from RO to SRO), and requalification training. These procedures specify that RO candidates for SRO have a high school diploma, four years responsible power plant experience (two of which are at Millstone 3), and one year as an RO at Millstone 3. The training program then includes: classroom and self study, on shift work, simulator training and a full scale simulator exam, and supervisory development training. The program specifies the path for a degreed engineer to SRO called instant SRO. This also includes prerequisites and a detailed training program. This is acceptabl l.A.2.3 Administration of Trainino Prograrns This item had short term actions to ensure that training instructors and facilities were upgraded. These actions were Interim pending the full accreditation of the licensee's training progra The licensee completed the interim actions, which were reviewed and accepted by the NRC in IR 50 423/85-82. The licensee's training program was accredited by INPO for Millstone 3 and the Millstone Station as a whole (for all ten of the INPO accreditable programs at the site). Millstone thus became a member of the National Academy of Training. This requires re accreditation every four years. The most recent accreditation was October 19,199 The licensee has begun the process for the 1998 re accreditation. This is acceptable, l.A.3.1 Revise Scape & Criteria for Ucensing Ex_ams Thin item addressed: exams in heat transfer and fluid flow, exam passing grades of at least 80%, simulator exams, mitigation of degraded core, and certain reactor manipulations for requalificatio The licensee has included all of the above topics in the curriculae for both RO and SR The inspector reviewed the curriculae and selected lesson plans. The licensee also includes in their training procedures a minimum passing grade of at least 80% and specifies a number of simulator exams as part of the training and qualification process. This is acceptable, l.B.1.2 Evaluation of Organization and Management This item requires the establishment of an Independent Safety Engineering Group (ISEG) with certain defined functions and responsibilitie ..
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The licensee describes the performance of the ISEG in TS 6.2.3, FSAR 13.4 A and procedure NOOP 3.04. The licensee has assigned the ISEG duties to the Nuclect Safety Engineering (NSE) Group who also performs the evaluation of operating experience. The inspector discussed the ISEG with the overall supervisor of NSE and the Unit 3 superviso The inspector also reviewed a sample of the ISEG quarterly reports and selected evaluations. The Inspector noted that one activity required of ISEG is to provide independent verification that human errors are reduced as much as practical. Currently the NSE human f actors personnel that are performing this function are also performing a line function of human f actors design and review. For example, the human f actors engineering expert of NSE is specifically called out by NGP 5.25 for design and operational reviews of control room design changes. The licensee stated that they are careful to not assign these personnel to review their own work. They also stated that this potentiallack of independence is recognized and that they are transitioning their staff out of this role. This item remains open pending a resolution of this issu LCAShort Terrn Accident Analvsis and Procedures Revision This item calls for licensees to perform analysaa of transients and accidents, prepare guidelines, upgrade emergency procedures, and conduct operator retraining. The emergency operating procedures (EOPs) should consider multiple failures and inadequate core coolin The NRC reviewed and closed this item for initial operation in irs 50 423/85 52 and 86-0 Since that time Westinghouse (WEC), the Westinghouse Owners' Group (WOG), and the licensee have continued to be very involved in the development and improvement of Emergency Response Guidelines (ERGS) and EOPs. The most recent version of the ERGS that the licensee has implemented is Rev.1B, dated 2/28/92. The licensee is actively participating in the WOG and ERGIEOP upgrade process. The inspector discussed the EOP process with operations and proccdures personnel and reviewed portions of the following documents: WEC ERGS, EOPs, Critical Safety Function (CSF) Status Trees, the Millstone 3 Step Deviation Document, and the NUSCO calculation for Millstone 3 on EOP Setpoint . The EOPs are based on updated analyses and NSSS guidelines and consider multiple ' failures and inadequate core cooling. The EOPs are periodically updated using the plant specific EOP Writer's Guide; and operators are retrained in the revised EOPs. This is acceptable, l.C.2 Shif t and Relief Turnover Procedures This item calls for procedures, checklists, and evaluations to ensure proper shift and relief turnover. Each oncoming shif t should be fully aware of critical plant status and system availabilit The licensee addresses this in FSAR 13.5.1.3 and procedure OP 3260, Section 1.16. This section contains detailed requirements for the turnover process. The inspector discussed the turnover process with control room personnel and reviewed selected turnover report The activities meet the intent of this item and follow the licensee's procedure. This is acceptabl __ - . _ _ _ . ._ __ -._ _ _ _ __ __ __ - . _ _ _ _ . o i
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This item is to ensure that the SS has a definite line of command and primary management I authority for safc operation of the plan ! TS Section 6.2.1 calls for procedures to define linet of authority and responsibilities, i These responsibilities are appropriately defined in FSAR Sections 13.1.2.2 and procedures , COP 200.1 and OA 1. This is acceptabl t
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1.C.4 Control Room ACCtaa This item requires that clear lines of authority and procedures be established to limit unnecessary access to the control room, r The licensee has addressed this in FSAR Section 13.5.1.3 and OP 3260, Section 1.7. The ! . inspector also observed acceptable control room access protocol during normal shutdown operations. This is acceptable, l.C.5 Procedures for Faadback of Onaratino Ernariance This item calls for the establishment of procedures for the feedback of operating experience, including such aspects as: responsibilities, steps in the review process, recipients, training and audit The licenses has assigned the responsibility for the review of operating experience to the Nuc! ear Safety Engineering (NSE) Group in the Nuclear Oversight Department. Procedure NOOP 3.04 provides all details of the process, as well as responsibilities and provision for audits. The inspector discussed the process with NSE personnel and reviewed items > processed by the NSE Group. NSE receives, assesses and processes information from the following sources: NRC, industry, equipment vendors, and internal events from Millston Additional details on aspects of NSE operating experience inspected are contained in IR 50-423/97 20 L l.C.B Procedures for Verification of Correct Performance of Ooeratino Activities This item requires procedures to assure an effective system of verifying the correct performance of operating activities, such as valve lineup The licensee has established independent verification in procedures WC 2, Work Control, WC-6, Determination and Performance of Independent and Dual Verification, and ACP-OA-2.12, System Valve Alignment Control. These procedures define the independent-verification process for various activities such as tagging, return of equipment to service, and valve lineups. This is acceptable.
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LC.7 NSSS VendDr Review of Procedures This item called for NSSS vendor review of low power test, power ascension test, and emergency procedures. This was a one time requirement that was met prior to plant startup and was documented in NRC IR 50-423/85 62. This is acceptabl . 1.C.8 Pilot Monitorino of Selected Emeroencv Procedures for Near Term Ooeratina License BITOL) This item called for NRC audit of Emergency Procedures for each NTOL epplican ; Millstone satisfied this item by developing their EOPs using the NRC approved Westinghouse ERGS. It was also a one time rather than an ongoing requitement. This was documented as complete in IR 50 423/86 08. The inspector reviewed selected EOPs which were well written and in conformance with the Westinghouse F.RGs. In OP 3272, the EOP User's Guide, the inspector noted that coverage of EOP steps of continuous applicability was weak. The licensee agreed to upgrade the discussion related to these steps. This le acceptabl l.D.1 Control Room Deslan Review
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This item required licensees to conduct a detailed control room dnsign review (CRDR) in accordance with NUREG 0700 in order to identify and correct human factors deficiencie The licenseo conducted the CRDR as documented in the Control Room Design Review Summary Report and approved by the NRC in the SER for Unit 3 (NUREG-1031).
The inspector discussed the process for ensuring any modifications to the control room are properly designed using appropriate human f actors principles. The licensee conducted an engineering review (3 ESAR 97 008) of the control room design area in the spring of 199 This review identified several conclusions and recommendations, including: revising NGP 5.25 and specification SP-EE 261, consider adding another human factors specialist, and an issue relating to whether the simulator and the control room designs agree. The inspector examined these items. SP EE 261 latest revision is 1990 and does not contain design guidance for computer based systems and wdeo display units (VDUs). There have been several advanced systems added to the control room without appropriate, consistent design guidelines (e.g., the Foxboro intelligent automated (IA) system for the Moisture Separator Reheators (MSRs), fire protection, EO temperature monitoring, the Autolog system, and SPDS upgrades). There are currently eight different con.puter-based systems in the main control room. Many of these systems are significantly different in their human systems interf ace, displays, and alarms. Some of these systems use embedded annunciator systems. Guidance on annunciator systems in the current specification is weak. The specification has not been updated to Rev.1 of NUREG-0700. Efforts are in progress to improve the conformance between the simulator and the main control roo Several CRs with corrective actions in this area were noted. An area that did not appear to be addressed was the new computer based displays for fire protection and automated logging (autolog).
The inspector also reviewed selected modification packages, related specifications, and the man machine interface review checklist of NGP 5.25 that was completed for those a
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modifications. These tended to refer to human f actors guidelines (e.g., NUREG-0700, and SP-EE 261) that did not contain appropriate guidance for advanced display In summary, the licensee has made a number of improvements to the control room consisting of advanced computer based displays that enhance the operator's ability to operate the plant. However, they have not established or applied appropriate human factors guidance for these systems. As a result they have introduced a number of different systems into the control room that ::reate unnect sary operator burdens. This item remains open pending further review by the licensos and discussion with the NRC on the control room design / human f actors issues discussed above, in the short term, enhanced guidance and additional training for the control room operators, as planned by the licensee, should address the adequacy of operational controls upon plant startup, in the future, more human f actors specialist input into the control room modification process is necessary to redur.e operator burdens, and reduce the potential for increased operator error LD.2 Plant Safety Parameter Disolav Consolg * This item required the design and installation of a Safety Parameter Display System (SPDS) in the control room of each plant. The licensee installed an SPDS as part of initial licensing. This was reviewed and approved by NRC in the SER for Unit 3 (NUREG 1031).
Generic Letter 89-06 on SPDS also notes that the SPDS for Millstone 3 was verified to be fully satisf actor In order to ensure the current status of the Unit 3 SPDS, the inspector reviewed the current specification for SPDS, observed the SPDS units in the main control room, discussed the system with the system engineer, and reviewed the various screens of the SPDS on the plant process computer. Specification SP EE 149A details the design requirements for the SPDS and procedure OP 3272 details the operating methods for use of SPDS by operator Section 7.0 of the TRM contains specifications requiring operability of the SPD Minor modifications to the SPDS system have been made over the years. However, the guidance references in the specification are out of date in that they do not contain current guidance on computer b9 sed displays. The Post-LOCA Cooling (PLC) status tree is not addressed in the EOP User's Guide, Section 1.6, " Monitoring Status Trees," or Attachment 4, " Control Room Usage of Status Trees." Operations stated that it is not included sinco they do not believe thst it serves a useful purpose as currently designed. Design engineering and c;:2 rations should coordinate any necessary modifications in order to develop a usable system. Also, the inspector noted that the navigation scheme for the PLC tree was not the same as for other trees and did not agree with the SPDS specificatio This item remains open pending the required specification revision, as agreed to by the license, and additionallicensee action to improve operator guidance in this area and enhance future oper5 tion / engineering coordinatio l.G.1 Training during low Pnwer Testing This item required training for new operating licensees as part of the initial low-power test program. IR 50-423/86 02 documents acceptable completion of the preoperational and
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low power testing in accordance with NUREG 0060 and 0737. This item does not apply to full power operation licensed plants. This la acceptabl U3 08 Miscellaneous Operations issues 08.1 iClosed) Notice of Violation 50-423/94 24 01; Ineffective Corrective Actions to flagluna Malfunctions and Dr.ficiencian of Main Steam isolation Valva Soianoid Valves (Clow Ell ite m 51 Inmonction Scone (929011 The scope of this inspection included a review of Main Steam isolation Valve (MSIV) solenoid valve problems as cited in NRC Notice of Violation (NOV) 50 423/94 24 0 NRC NOV 50-423/94 24-01 specified that corrective actions were not effective in x.... precluding the recurrence of malfunctions and deficiencies of the MSIV 2A/B solenoid valves. A pin failure occurred in solenoid 28 during partial stroke testing of the MSIVs on September 8,1994. In addition, pin failures had occurred on the 4A solenoid and 4B solenoid in October and June of 1992, respectivel The inspector reviewed the licensee's corrective actions to address the concer Ohaarvations and Findinom NRC Inspection Report 50 423/94 24 identified repetitive failures to achieve acceptable stroke times for the MSIV 2A/B solenoid valves. During the period between 1990 and 1994, there were ten instances when the 2A/B solenoid valves f ailed to meet tne stroke time requirement of 1.1 seconds. The solenoid valve stroke time of 1.1 seconds is required to ensure that the associated MSIV closes within a total time of five seconds, which is the TS limit. Additionally, pin failures had occurred in the safety-related 2B solenoid valve, and nonsafety-related 4A and 4B solenoid valves during the period between 1992 and 199 As a result of the NRC Inspection 50 423/94 24, NU Letter B15052 was submitted to the NRC which discussed the licensee's commEment of corrective actions to resolve the MSIV solenoid valve problems. These commitments included the following items:
* Establish an optimal surveillance test frequency to assure greater availability of the MSIV solenoid valves; * Collaborate with the solenoid valve supplier (Sulrei Thermtec) to evaluate the pin material and fabrication process, and to determine if design changes could minimize the possible recurrence of pin failures; and e Develop appropriate administrative controls to ensure that stroke travelis monitored during future stroke testing of the MSIV solenoid valve An MSIV Action Plan Task Group was established to evaluate the potential failure mechanisms which caused the slow MSIV solenoid valve stroke times. It was found that i_ .
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the poor MSIV performance was due to mechanical binding of the solenoids, the solenoid actuating spring was not strong enough to overcome the rolenoid operating pressure, and the pin material was improperly heat treated. As a result of repetitive functional failures, the MSIVs have been categorized as an A(1) Mainterance Rule system, in accordance with the Maintenance Rule Action Plan, physical modifications were performed and a schedule of MSIV testing was developed to improve reliabilit Physical modifications on MSlV #2 and #3 solenoid valves were completed during RFO 5 in accordance with PDCR MP3 95-005. These modifications included the replacement of the solenoid sprhig with another of a higher spring constant (per DCN DM3 S-0389-95), case hardening of solenoid piston rods (per DCN DM3-S-0369 95), and the replacement of the attenuators with variable resistors in the solenoid circuitry (per DCN DM3 S 0297 95). The variable resistors allow adjustment to higher operating voltages to increase the holding powet of the solenoid valves because of the larger spring force of the redesigned sprin Based on a field walkdown, the inspector verified that variable resistors were installed to replace the attenuators in the solenoid circuitry. No operability concerns were identifie Stroke tests of MSIV solenoid valves were performed after the modifications per Surveillance Procedures SP 3712AA and SP 3610A.1. The data trenda of the safety-related MSIV 7A/B solenoid valves after March 10,1995 indicated that stroke times for all 2A/B solenoids were less than 0.6 seconds, These stroke times were within the acceptance criteria of 1.1 second The licensee plans to install new solenoid valve block assemblies during the sixth refueling outage to gain the best possible operating experience for the solenoid valves. The new solenoid valve design is exper.t id to provide longer service life based on full power operation. Vendor calculations of solenoid coilI;fe resulting from the RFO 5 modifications indicate that a coillife of four years is expected under worst case conditions when batteries are recharging. Thus, sufficient margin exists in the four-year service life of MSIV #2 solenoid valves before the installation of new solenoid valve assemblies during the RF0 6 period. The inspector had no further concerns with the licensee's plans to install the new solenoid valve design during the scheduled RFO 6 perio Conclusions Licensee corrective actions to address the MSIV solenoid valve problems were determined to be acceptable. The data trends of safety-related MSIV 2A/B solenoid valves after the RF0 5 modifications showed that the sttoke times for all 2A/2B solenoids were within _ pcceptable tiene limits. Since there is a margin of a four-year service life for the MSIV #2 solenoid valves af ter the RF0 5 modifications, the licensee's plans to install the new solenoid valve design during the RF0 6 period were considered to be reasonable. Thus, Violation 50-423/94 24-01 is considered closed. SIL ltem 5, which was also inspected and documented in IR 50-423/97-02 is also hereby close e O
U3.Il Maintenance U3 M1 Conduct of Maintenance M 1.1 Soent Fuel Pool Purification Modifications Inspection Scoon (62707) A spent fuel pool purification modification. st arted this inspection period, rerouted non-seismic spent fuel pool (SFP) purificatior su ' on and discharge and refueling water storage tank (RWST) makeup lines to penetrate m' e :.;her heation a the spent fuel pool wal This relocation was necessary since it was determined that in a seismic event the piping could fail and potentially drain the SFP below the spent fuel pool cooling suction line, thereby causing a loss of spent fuel pool cooling. (Section U3 M8.1 provides further detail on this scenario.) The inspector attended a PORC meeting to review the diving procedure, observed predob briefings and the partialinstellation of equipment to facilitate the spent fuel pool purification piping modification, and discussed the modification with the system engineer and radiological protection (RP) dive supervisor, Observations and Findinos Two special procedures (SPROCs) were used to control the observed activities. SPROC 97-316, DCR M3-97020 Implementation infrequently performed test evolutions (IPTE), controlled the preparation, modification, and system functional testing. Since the modification involved cutting and capping three lines which penetrated the SFP wall below the normal water level, the licensee decided to install a " habitat", a box with three sides and a floor, which was lowered into the spent fuel pool and positioned against the fuel pool wall encompassing the three affected lines. After the habitat was installed, the water was pumped out of i' to create a dry environment for the cutting and capping evolution. The habitat was fitteu with a seal which, aided by the force of the FFP water on the outside of the box, formed a virtually leak-tight seal. The installation and emoval of the habitat required the use of a diver in the pool. Control of the divers was proceduralized in SPROC . 97-3 24, HP Controls on Dive Activities h,. Spent Fuel Purification Modification PORC review of SPROC 97 3-24 was thorough as evidenced by clarification that both spent fuel pool coolin] pumps should be shut off and tagged during the diving evolutions; the procedure previously sta+ed " spent fuel pool cooling pump." PORC questioned the divers on their contingency procedures to ensure they hao and understood them,. Also, PORC required the SFP water to be sampled after the diving evolutions were complete to verify that boron concentretion was not affected after rinsing the diver and equipment with unborated wetor. The inspector noted good discussion during the PORC meeting and verified the appropriate changes were subsequently made to the procedur Briefings were conducted for the dive evolation and the entire IPTE before the modifications commenced. The licensee's dedicated dive supervisor conducted a thorough dive briefing, attended by radiological protection, emergency medical technicians, safety, nuclear oversight, ad diving personnel. The briefing thoroughly covered the radiological
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aspects of the dive activity, including a discussion of recent diving problems at another nuclear power plant. These problems were outlined in detail and actions to prevent similar problems at Millstone were described. The inspector had reviewed NRC Information Notice (IN) 97 68 prior to the briefing and verified that the licensee had an accurate understanding of the issues and had taken appropriate steps to preciude similer problems. This briefing was attended by maintenance, engineering, RP, diving, Nuclear Oversight, and other appropriate personnel. Procedure adherence, personnel and equipment safety, effective communication, FME, and technical specifications were discussed. In addition, termination criteria were stated and radiological work permit information was presente The inspector verified that the work and diving activities were conducted professionally in accordance with the SPROCs. The divers were aware of their tasks, the expected dose rates, and use of hand-held radiation meters. TLDs and electronic dosimeters were placed on the divers as specified by the SPROC. The electronic dosimeters were monitored by an RP technician in the spent fuel pool area throughout the diving activity. When one of the dosimeters took a step increase the diver was taken out of the water. That dosimetu was inspected and determined to have malfunctioned. This conclusion was supported by the expected readings on the backup dosimetry. The modification work was first stopped when confirmatory measurements of the piping geometry in the poolindicated the habitat may not fit as expected and attempts to install a pipe plug at the end of the spent fuel pool purification discharge piping failed. The evolution was stopped until an evaluation of the informaHon was completed, modifications to the habitat were made, a pipe plug was modified, and procedures were revised. The pool was placed in a safe condition when the decision to stop the work was made. The decision. so bacx out of the procedures resulted in a two week delay of the work to accommodate equipment modifications and unrelated operations evolutions. The decisions to stop the work were evidence of conservative decision makin FME controls were in place as tN area around the spent fuel post was designated an FME area. Close uttention to material entering and exiting the area was observed in addition, although the area on the other side of the pool was not formally designated an FME area, the RP dive supervisor controlled it as such. Although this control was not formal during the first attempt to install the habitat, it was followed by personnel entering the area from that side. The inspector noted that formal FME control of that area was instituted during this subsequent performance of the work. Although not required, this FME control was conservative to ensure the integrity of the spent fuel pool. While the diver was installing the habita2 he lost control of a wrench, which had been tethered to his arm. The wrench drifted near the spent fuel storage racks where it was left until the habitat work was completed. It was later recovered using a long-handled tool. The insper, tor noted that the loss of the tool was immediately communicated, visuallocation of the tool was made with the in-water cameras, and no attempt to have the diver retrieve the wrench was discusse The incident was discussed with the diver and effective actions were taken to prevent a repeat occurrence. Nuclear Oversight and RP and operations management oversight presence was noted during the habitat installation. The modification work continued at the end of the inspection perio _ __ _____
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r Conclusions Preparation and installation of the " habitat" for spent fuel pool purification piping modifications were well coordinated and controlled. involved personnel, including RP technicians and divers, were f amiliar with their responsibilities and performed well. The RP department effectively used lessons-learned from other utilities to control the diving activities. Modification work was appropriately stopped and/or reschr.juled to accommodate operations, equipment, and procedutalissue U3 M2 Maintenance and Material Condition of Facilities and Equipment M2.1 tient Exchanger Pmformance Generic letter 89-13 (Undate - SIL ltem 36) a, IDsoection Scone (92902) Generic Letter (GL) 8913 was issued by ihe NRC to discuss problems with service water (SW) systems and to establish a recommended program that would ensure SW systems can meet regulatory requirements and properly remove heat from safety related components. Operating experience has shown problems with biofouling, corrosion ard erosion leading to flow blockages, reduced heat transfer coefficients, and leaks in the SW systems. NU has supplied a number of response letters to the NRC for this GL. The inspector reviewed the licensee's responses and programs to address the concerns addressed in the G Observations and Findings The GL states that it applies to any systems that transfer heat from safety related components to the ultimate heat sink. Intermediate systems used to transfer heat are also included in the scope of the GL. However, intermediate systems can be classified as closed cycle systems and thus not subject to all parts of the GL if they are not subject to significant contamination, have their water chemistry controlled, and do not directly reject heat to the heat sink. Unit 3 has severalintermediate systems that qualify as closed cycle systems per the GL. Two systems that are in question are the closed cooling water systems for the charging pumps (CCE system) and the safety injection pumps (CCI system). The inspector noted that these systems are filled with water from the reactor plant closed cooling water (CCP) system but that the water in CCE and CCIitself is never sampled or chemically controlled after addition. Procedure CP 802/2802/2802AA samples and analyzes the other clused cooling watar systems but not CCE and CCI. The licensee issued a memorandum from Technical Support to Chemistry requesting that these two systems be adoed to the current plant sampling procedure. The licensee then sampled the systems and found the levels of corrosion inhibitor low; a CR was writte .
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Item 1 - Surveillance and controls to reduce flow blockage due to biofoulina item I. A - Intake structure GL 8913 calls for inspections of the intake structure for biological fouling, sediment, and corrosiun; it also specifies that any fouling accumulations should be removed. The licensee has committed to annual inspections by divers and/or videotape, and refurbishment, removal of all debris frem the intake bay, and cleanin The licensee is now using divers to inspect and videotape the entire underwater intake structure area. This activity is described by preventive maintenance automated work orders (AWOs) and by Step 1.2.3 and Attachment 5 of procedure EN 31084. The inspector had three comments on these documents: (1) The three documents were not consistent in their instructions and could lead to confusion as to exactly what was needed to be done; (2) the instructions did not require that all fouling, debris, and sitt be removed; in fact it permitted 2 feet of silt to remain, without justification: (3) the instructions did not clearly state that the SW pumps should be inspected and cleaned. The licensee issued Change 1 to EN 31084 to specifically add the SW pumps to the inspection The inspector reviewed a portion of the videotape of the summer 1997 diver inspection and toured the intake structure with the system engineer. The above water areas and squipment appeared to be in good material condition. The videotapes showed significant underwater feuling with marine growth, including mussels. The system engineer stated
' hat this had now been partially cleaned, but that the remainder was delayed due to environmental discharge concerns; as a result trouble report (TR) 26M3101938 was issued with a due date of 12/23/97. He further stated that all cleaning would be accomplished before plant stanup. At the end of the inspection period, cleaning of the intake structure had recommence Item I.B - Chlorination I
This item of the GL calls for continuous chlorination of the SW system. The licensee has committed to continuous chlorination and to regularly scheduled thermal backwashing of the circulating water (CW) system to clean the intake structure bays. Tney also have stated that they take daily samples of free available chlorine (FAC) and make reports to management to ensure prompt action if measurements drop below an effective leve Unit 3 has a hypochlorite system which provides continuous chlorination of the SW system by injecting m the intake structure just below the bowl of the SW pumps. Both trains of SW are continuously in operation with a 72 ho'ir technical specification LCO in Modes 1 to 4. The chlorination also is drawn into the CW trains when they are running. Chemistry takes a daily sample of the SW chlorination per procedure CP 3804AG. The results are logged and in.c;ded on the daily status report The inspector reviewrithe chemistry logs und observed a chemist drawing a sample of SW for analysis. The inspector noted that procedure CP 3804AG, Step 1.2 discusses maintaining a FAC level of 0.12 to 0.17 ppm to minimize biofouling. Steps 4.1.1 through j
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4.1.5 call for increasing the chlorination when the level drops below 0.12 ppm. Pe.%dically during the current plant shutdown, the CW pumps are run for several hours. During this time the FAC levelin the SW system drops noticeably, sometimes to 0.05 ppm. The licensea did not take action to increase chlorination but rather relied on a memorandum response to CR M1971971 that states that periodic cessation of chlorine injection for up to 30 minutes for strainer backwash and continuous low-level chlorination for an 8 hour shif t stillis expected to prevent mussel settlement. The memorandum further stated that this expectation should be confirmed by frequent inspections. The licensee has performed inspections over the last several months and found no mussel growth in the SW Syste The inspector noted that the procedural controls were weak in that there was no clear lower acceptance criteria for FAC, there was no lower value of FAC on the data sheet, the data sheets were not being circled or annotated when FAC was out of specification low, and the memorandum methods for times of low chlorine had not been proceduralized. The licensee is considering a procedure revisio The licensee is currently experiencing difficulties with SW strainer operation due to restrictions on chlorine discharge into certain areas of Long Island Sound. Modifications are being considered that change the hypochlorite injection point to beyond the straine Considering past problems with mussel growth in the SW system, the inspector noted that any changes, which would tend to reduce such protection and possibly reduce SW system reliability or availability should be carefully evaluated and justified. The licensee provided the Safety Evaluation (SE) that was performed for this proposed modification. This SE addressed the potential concern for reduced effectiveness of the hypochlorite in preventing future mussel growth problems. The inspector reviewed the SE, and noted that it determined that no unreviewed safety question existe The i.'9ector reviewed the preventive maintenance schedule for thermal backwashing of the condenser and circulating water system and concluded it was being performed regularl Itern 1. C - Flushina. flow testino. and lavun This item of the GL calls for flushes and flow testing of infrequently used SW loops. It also calls for testing of other SW components on a regular schedule to ensure they are not fouled or clogged. Further, it adds cautions about layup of idle SW loop ' NU notes that the large majority of the SW system sees full flow at all times. Exceptions are the recirculation (RSS) coolers, the EDG coolers, the post accident sample system (PASS) coolers, and smaller dead legs for the emergency SW supply to control building chilled water, auxiliary feedwater (AFW), the spent fuel pool, and the idle pumps in each train. Systems that do not see full flow were reviewed. The RSS coolers are flushed using SPROC 96-3-07, and the EDG coolers by SP 3626.13. The PASS coolers are normally isolated and drained. They are functionally operated by taking a sample every six months per procedure SP 3885, however there is only a minimal partial flush and no flow tes The inspector toured the plant areas and observed the dead legs. Two of the four dead legs for emergency SW to control building chilled water are periodically drained and the
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other two have the valves opened for an operability inspection. The spent fuel pool cross-connect line has a spool piece removed, then two closed isolation valves to the SW - system. The line between the valves is drained. There is a dead leg of several feet between the SW line and the first isolation valve 3SWS*V700. During refueling outage No. 5, an inspection found some mussels in this dead leg. This was cleaned and a modification (EWA 93061) scheduled for the next refueling to move the isolation valve closer to the SW header in order to minimize the dead leg. The licensee has agreed to conduct additional checks of this dead-leg piping during the current outage. The AFW dead logs run from one elevation in the ESF building to the next and between compartment They are quite long, are not on a regulcr inspection program, and were not recently flushed or inspected. Each SW train has two SW pumps, with only one running at a time. When a pump is secured, its discharge valve is shut, leaving a dead leg between the pump discharge check valve and the discharge isolation valve. This also needs to be considered, since the pumps may not be rotated frequently enough to address musse! buildup. For all of the dead-leg piping, the licensee has agreed to review the need for additionalinspections or flushing operation Flow tests for the RSS coolers are performed as part of SP 3646A.17. The inspector reviewed flow test data and an engineering evaluation associated with the last test performed for the RSS coolers in July 1996. The visualinspection, performed after the test, found some minor fouling with mussel shells and small pieces of ARCOR coating material. The coolers were cleaned and reflushed satisfactorily. However, this finding and other findings of loose ARCOR coating led to repair work on SW ARCOR during 199 Flow tests for EDG coolers are performed weekly per SP 3626.13 and recrHed on OPS Form 3626.131. The inspector reviewed selected completed data on tb .orms and also the EDG trends kept by the SW system engineer. Data appeared satisfactor Regardirr tests of other components to ensure they are not fouled or clogged, the licensee has established SP 3626.13. This procedure collects weekly data on the flow rates, differential pressures, and differential temperatures for all normally operating heat exchangers and loops in the SW system. The data are compared to acceptance criteria on the procedure forms. The inspector reviewed selected data and noted that the acceptance criteria were met. The licensee is currently developing a trending program in the Technical Support Department to further evaluate the dat Procedure 3626.12 requires fresh water layup for any SW component or loop that is idle for more than three days. Additionally, operations documents a weekly surveillance to verify that heat exchangers are in service, fresh water layup, or drained and out of servic item 11 - Test orogram for heat exchanger (HX) canability GL 8913 calls for a test program to verify HX capability of all safety related HXs cooled by service water. Enclosure 2 to the GL provides an example of an acceptable progra Alternative, but equally effective programs are permitted. The licensee were required to also evaluate closed-cycle system HXs to determine whether the test program needs to be extended to these components as ell, o
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-The licensee has sent numerous response letters to the NRC that concern item II. The first' - ' letter,1/25/90, gave a ' proposed ' program and selected an alternative method to that of , - Enclosure 2. The 5/31/91 letter stated that item 2 was complete, but slightly changed the . ,
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detailed actions.' Subsequently, five other letters were submitted that made additional . ~ , changes to the' program and identified parts of item 2 that were not completed as 'l e committed. The inspector noted that the aggregate of the responses was confusing, no
' longer accurate in places, and did not appear to meet the intent of item 2. The licensee j
- has also recently evaluated their program and is in the process of upgrading it to meet the ~ q
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- ~ recommendations of the GL. The inspector noted that the program probably needed to be
- **nded to the CCE and CCl systems based on the finding noted above with respect to
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. nical control of these two systemsi The inspector reviewed a draft of the new' .
ogram and one approved test procedure for testing the EDG HXs. These will be reviewed
' in more detail when the program is approved.- The inspector also r,oted that the licensee
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.has agreed to the submission of a revised, consolidated, and updated response to the NRC- d - to item 2, as appropriate, q
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' Itam lli - Routina Innoaction and maintenance program GL 89-13 calls for a routine inspection and maintenance program to ensure that open cycle - >
SW system piping and components do not degrade due to corrosion, erosion, protective :
. costing f ailure, silting, or biofouling. This program should remove excessive accumulations ,
and repair defect . . Procedure EN 31084 establishes the inspection frequencies, requirements, and corrective ,
' maintenance for ths SW eystem. All HXs are inspected on a routine defined schedule that t e - is being coordinated between the procedure and the PM program. Refueling outage Inspections are much more detailed and entail draining, disassembly, and internal pipe
- . inspections. All of the above GL attributes are addressed in the inspections. The inspector , reviewed selected completed inspection sheets and summaries of corrective actions taken.
The SW. system refueling outage reports.were particularly detailed and informative _. The licensee's program is identifying problems and taking actions to correct them. The ARCOR q coating issues were noted and will be Wdressed in SIL ltem 5 Item IV - Confirmation of licennina banin
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. LGL 8913 calls for a confirmatior that the service water system will perform its intended . function in accordance with its censing basis. This activity should include system
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a# 4 in their 11/5/93 letter to NRC (014643) NU noted that the licensing basis evaluation was completed, and they confirmed that the SW system will perform its required safety function at the d,ssign basis SW temperature of 75'F. The inspector briefly reviewed , L Calculation No. 90-069-1065-M3 that evaluated the SW system's design basis for GL'89- ,
; 1 /Additionaily, Unit 3 has performed an in-depth configuration management program (CMP)
during the current' shutdown that included the SW system, the CCP system, the CCE
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system, the CCI system, and the EDG cooling water system. The CMP incidded detaile reviews of all FSAR commitments and design calculations, preparation of design basis) ' - summary reports, and detailed system walkdowns. Identified problems'were addressed ,
:through the CMP UIR and OIR systems as well as through the corrective actions program
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'as condition reports. The inspector reviewed selected portions of the CMP-develope :;
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information for the cooling water systems, including the design basis summaries, and; marked-up P&lDs from the system walkdowns. The Unit 3 system engineers also g performed walkdowns prior to the CMP walkdowns and identified a variety of system - ! discrepancies, which were corrected through the trouble report system.-
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ltam V - Confirma+3nn of maintenance /noaratino oractican and trainina , GL 8913 calls for a confirmation that maintenance practices, operating and emergency ;
,rocedures and training related to the SW system are adequate to ensure the system will 1 ~ . function as intended and that operators will perform effectively. The intent is also to < reduce human errors related to the SW syste ' - Training for the SW System was addressed in the 1/25/90 response letter, Attachment 5, and further confirmed in the 5/31/91 letter. The licensee did not specifically address other
- cooling water l systems in their response to item V. However, training for other cooling - -
- water systems is performed as part of the licensee's operator training program and the-engineering t.aining program. Human errors are addressed through tne licensee's training :
- via their STAR program, simulator training, and by incorporation of operating experience into the tra;ning. . Maintenance trainir
- g is performed primarily at the component level rather than the system level. Electrical, I&C, and mechanical personnel all receive initial and periodic training to address their needed skills. Operating experience is also factored into .
maintenance training to prevent human errors. This review did not look further at the ' details of the licensee's training program, n As part of the CMP discussed in Item IV, the licensee performed a System Assessment per PI 32 that reviewed various types of procedures, including operating, maintenance, and emergency procedures against the statements of fact developed from the FSAR, Technical 1 , Specifications and other documents'. The results of this System Assessment were ' summarized in Memorandum MP3-DE-97-1100 and the closure memorandum fo. AR
- .96036125 01. Identified problems were addressed through UlRs and CRs.
1 Conduelon Review and inspection of the technicalissues involving licensee compliance with the regulatory guidance of Generic Letter 89-13 continues.- SIL ltem 36 addressing Generic . Letter 89-13 is hereby updated. Certain questions' and concerns, as noted above, remain
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- to be addressed by the licerssee. before thia SIL item can be closed.
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U3 M8 Miscellaneous Maintenance issues M8.1 (Undate) LER 96 037 Soent Fuel Pool Cooling Svstem Potentially Inocerable Followino a Safe Shetdown Earthouake Due to Failure of a Non-Seismic Connectino Pine (Undate - Sit item 701 insoection Scone (92902) A licensee engineering review determined that a f ailure of the non-seismic purification lines connected to the spent fuel pool (SFP) could result in a loss of SFP cooling, as a result of a postulated safe shutdown earthquake (SSE) condition. The purification lines are connected to the SFP at the same elevation as the SFP cooling system suction lines. Because of this, drain down of the SFP to the level of the purification line penetrations would result in the SFP cooling line being partially out of the water. SFP cooling would be unavaiiable until , repairs to, or isolation of, the purification lines could be accomplished and makeup provided to restore the SFP level. This condition was caused by an oversight in the original design of the plant. The discovery of this flow path out of the SFP led to another engineering review to determine if there were other similar flow paths out of the SFP. The spent fuel shipping cask, the transfer canal area and the refueling cavity drains were reviewed. Loss of water out of the SFP and the uncovering of the SFP cooling lines would not cause the water level to drain lower than ten feet above the spent fuel, however it would place Unit 3 outside of its design basi Observations and Findings The inspector reviewed LER 96-037, SIL item 70, and ACR M3 96-0898, and other
- associated documentation and engineering drawings. The inspector reviewed the corrective actions that the licensee divided into two categories;immediate and short term. The ten completed corrective actions reviewed by the inspector and taken by the licensee were
- 1)
perform a root cause evaluation and reportability determination; 2) establish administrative controls to prevent draining the shipping cask and transfer canal areas; 3) provide administrative controls for refueling cavity drain valves; 4) establish a database linking licensing design basis to components for maintenance rule systems; 5) establish a self-assessment and corrective action program within the Millstone 3 organization: 6) develop calculations for the SFP gates: 7) finalize the seismic qualification for the drain down of the shipping cask and transfer canal areas: 8) evaluations to demonstrate the seismic qualification of the SFP cooling lines to the shipping cask and transfer canal area; 9) revised the FSAR to indicate that the flow path from the seismic Category 1 Refueling Water Storage Tank is through the non-seismic purification system; 10) lessons learned were shared with engineers; 11) performed an engineering investigation which evaluated and documented the potential drain down path The remaining corrective action is the completion of the modifications to the . Spent Fuel Pool System which includes cutting the Spent Fuel Purification pipes, rerouting them, and then rewelding the Spent Fuel Poolliner enclosure. The inspector also observed the preparations for modification of the Spent Fuel Poolin the field. (Portions of this modification are discussed in Section U3 M1.1.)
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e . 45 Conclusions The completed corre.:tive actions taken by the licensee are deemed adequate. LER 96-037 remains open pending completion of the changes to the Spent Fuel Pool piping. SIL ltem 70 is hereby update M8.2 (Closed) LERs 50-423/96-042 & 96-048- Problems with Containment Fuel Dron Radiation Monitors (Undate - SIL ltem 701 Insoection Scone (929021 Unit 3 has two gamma radiation detectors in containment (3RMS*RlY41 & 3RMS'RlY42) that monitor Ceneral area radiation around the refueling area in order to detect a fuel drop accident. Upan detecting radiation levels of 1 Rem /hr they close the containment purge system isolation valves. In the early 1990's,it was detarmined that the actuation from the monitors should have been classified as an Engineered Safety Feature (ESF) and the licensee initiated a Technical Specification (TS) change to move the requirements for the monitors to the ESFAS instrumentation section. When this TS change was approved in June,1996, it was required to be implemented in 60 days, which included time response testing that had never been performed for these instruments. The licensee did not perform the testing within the required 60 days and as a result issued LER 90-042. When the testing was performed, the instruments exhibited a total reponse time, from detection to valve closure, of about 20 seconds, which exceeded the required response time of 5 seconds: thus, LER 96-046 was issue The licensee determined that the original plant design for the response time of the instruments was inadequate to meet the required 5 seconds. The design process relied on vendor calculations and input, and was never "enfied by the plant in the derign pro :ess or as part of the plant startup or inservice test p . grams, Observations and Find;nas Corrective Actions: The licensee has implemented a design change for the radiation monitors to improve their response time (DCR M3-97032), and has also reanalyzed the fuel drop accident to increase the allowable time between the fuel drop and the purge valve isolation from 5 seconds to 16 seconds. The procedures and the Technical Requirements Manual (TRM) have also been updated to correspond to the new response time. The inspector toured the containment area and observed the detectors, the containment purge line and valve arrangements. The inspector also reviewed the design change, the new calculations, and ' the test results for the modified radiation monitors. The monitors now meet the 16 second response time requirements with a total response time of about 8 seconds. The detectors j themselves are exempt from time response testing, per Safety Evaluation Report 3TRM ! 3.3.2, Rev. 5, dated 11/1/96, due to their negligible response time of several I microseconds. An FSAR change (97-MP3-362) is in process to reflect the implemented l changes. The inspector noted that the draft FSAR change did not correct duct length from l l
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190' to 211'AThe Regulatory Compliance Manager agreed to revise the draft to the proper _ _ value of 211'. The inspector also observed the control room indicators, recorders, alarms, e and procedures to be used in the event __of a fuel drop accident. The inspector noted that -- , the recorders (on Panels 3RMS*RAK1 A & 1B) in the control room were al! two pen l . recorders cad did not employ good human factors practices, in that there were no' labels toJ , describe the parameters for each pen or units being recorded. This was discussed with site f
. human factors personnel, who issued CR M3 970566 to add appropriate label i As a broader corrective action, the licensee identified the following actions in their root' +
cause analysis. They would perform a design review of the Chapter 15 FSAR analyses to - ensure that vendor time response data is supported by test results for all safety related, non-ESF, actuations. The licensee completed this engineering evaluation and did not- - identify any additional instruments with untested response time _ Preventive Actions: The licensee has identified a number of actions and controls that should serve to prevent similar occurrences. The plant has recently upgraded the Design Control Manual and ; vendor interface controls, in order to ensure th: design inputs and testing are properly addressed. The CMP has verified allimportant statements of fact from the FSAR, including
.a verification that test ng i was performed as needed. The licensee also had a contractor
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(Scientech) perform a review for Unit 3 to verify that each Technical Specification ,
surveillance requirement svas implemented by a plant procedure, d
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Part of the problem with the late implementation of the TS change (identified in the LER) related to poor communication between l&C and licensing and an incomplete understanding , by l&C personnel of the action item tracking system. The licensee performed a briefing of affected l&C personnel and also established a weekly briefing of the I&C Manager on action item statu The licensee performed training of licensing department personnel responsible for TS implementation to ensure they are knowledgeable of thei aquirements and responsibilities.
Further, a review was performed of the implementation of the last 16 license amendments; no_ discrepancies were found.
. Tha licensee issued a new licensing department instruction (MP3 LDI 03) to supplement DC 10 and to address in more detail the actions required to properly implement TS and license amendments.. The inspector reviewed the implementation of LDI 03 with the Regulatory ; } ' Compliance Manager and the License Amendment Coordinator, c.- Conclusions
:The licensee has adequately addressed both LERs. The corrective actions are acceptabl : The safety significance was limited in that there has not been a fuel hanoN9 accident et = Millstone that required the detectors to function if there had been such an accident, tben !
the detectors would have functioned, but possibly not within their analyzed time. Thus,
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O , 47-ithe_ consequences of such a postulated accident may_have been greater than analyze LERs 50-423/96442 and 96 046 are now closed. SIL ltem 70 is hereby update _ _ _ U3.Ill Enginaaring U3 F1 - Conduct of Engineering _- E Review of Itama to be comolated Affar Restart Inanaction Scone 137550) in a lette.r dated April 16,1997, the NRC requeste'd, in part, that the licensee provide the following information pursuant to 10 CFR 50.54(f):
'o For each unit, the list of significant items that are needed to be accomplished prior to restart; e- For each unit, the list of items to be deferred until after restart; and, o For each unit, the process and rationale used to defer items until after restar The letter also requested updates approximately every 45 days for the first two items. On October 21,1997, the licensee provided tne second update to the list of Unit 3 items to be deferred after restart.- The information was provided in three sections including 1) a complete list of all deferred items; 2) a list of items added since the last update; and 3) a list of items removed since the last update. The inspectors reviewed a sample of items and found the sorting of the items to be accurate (the complete list was found to include the
_ added items and the removed items had been deleted from the complete list).
Based on the previous NRC review of the Unit 3 deferred issues list (NRC IR 50-423/97-202), this inspection focused on the list of new items added on this update. The - inspectors reviewed the information to assess the content of the list and whether the deferrals were appropriate, and that they met the criteria for deferral as stated in the -
~ licensee letter of May 29,199 ' - b, '
0hearvations and Findinan s ! Approximately 2400' items were added to the deferred issues list for Ursit 3 during the-
: October 21,' 1997 update. The inspectors reviewed the one line description of all of the- -ltems and selected approximately 250 for a more detailed review. In selecting the items for further review the inspectors considered the safety significance of the systems and the potential for system _ operability to be affected, based on the line description. Th :inspecto.s reviewed supporting documentation for these items, and for selected items - discussed the issues with the licensee staff to obtain sufficient information on each of the ' Items to determine if deferring the item was appropriat . _ ..- _ _ . . _ . _ _ .._ _ __ . _ _ . . _ _ _ . _ . - . _ _ _ _ __
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: The inspectors found that the decision-making process for deferring items was conservative and as a result the items on the deferred items list would not affect safe plant
_ ooeration. In general, the licensee was~able~ to provide a good basis for including the items u on the deferred items list. i As a resu!t of this inspection, the licensee ' revised the status of four_ items from deferred to' required prior to startup. iThe licensee wrote CRs to documen :
- these items.L The inspectors also' noted that if these items had been deferred, they.would . ;
O ' not have a significant impact ,on the safe operation of the plant. ; However, the items did .
: meet the licensee criteria to be completed prior to restart.-
l- The issues reviewed by the inspectors also included several items that appeared to have 3 ' E potential human performance implications that could increase the potential for operator i: errors.'_ Although the licensee's screening criteria does not specifically address human: ; performance issues, the inspectors found that the licensee was generally sensitive to the : ,
= concern and made appropriate decisions in evaluating the issues for deferral. An example
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1j of this type of issue was that several safety related pumps were painted the opposite color - o
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p yof the safety train with which they were associated. (The two safety trains'are designated ' orange or purple _at Unit 3.) This item was on the deferred list but during the inspection,_ , the licensee decided to repaint the pumps prior to restart to minimize the potential for j operater error.
I During a previous inspection of the deferred issues (NRC IR 50-423/97-202) the NRC issued a notice of violation as a result of findings that the list was not complete and
- accurate.-- The licensee found that the cause of the violation was inadequate management 6 - oversight that resulted in the initial submittal, and the first update, not receiving adequate management review or attention. Corrective actions included management defining the roles and responsibilities of personnel developing the list and the development of a specific w ,
- verification and validation process to be used in generating the list. PORC reviewed and
' ' approved the _ verification and validation process and was also tasked with reviewing additional submittels, including the October 21,1997 updat '
' During the cunent inspection, the quality of the list was found to be improved. -However the inspectors noted that four CRs (M197-2312, M2-97-2487, M3 97-3739, M3-97- * i 3740) were written by the recovery oversight group to document problems that were , identified during the preparation of the October 21,1997, submittal. Violation 50-423/97-
. 202 08 remains open pending licensee resolution of the issues documented in the CRs and
. followup inspection by the NRC to review any additional findings and corrective action c, Conclusions The' inspectors concluded that the licensee had improved the review and approval process
: to provide additional assurance that the list would be complete and accurate. The process resulted in the list containing items that were appropriate for deferral and overall the conte _nts of the list reflected a conservative decision-making process. The inspectors did
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;not identify any issues that, if not corrected prior to plant restart, would have resulted in a
- . significant safety concern during plant operation .
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49 U3 E2 Engineering Support of Facilities and Equipment E Potential Electrical Seoaration Violations (Closed - SIL ltergjll (Closed) LERs 50-423/96-049. 98-15-05.96-045 Insoection Scone (92903) LER 96-049-00 and its supplement, LER 96 049-01, documented a concern regarding deviations of minimum separation distances betwr.en Class 1E and non-Class 1E cables in the cable spreading and instrument rack room LER 96 015-05 (an update of LERs 96 015 00,01,02,03, and 04) identified additional Main Control Room (MCR) panels in which noncompliances with electrical separation requirements were found. ACRs M3-96-0080 and M3-96-0081 documented these potential noncompliances in specific MCR panel LER 96-045-00 identified the improper application of Wyle Lab test results for the basis of reduced electrical separation between Class 1E and non-Class 1E circuit The inspector reviewed the licensee's ongoing corrective actions to address the above concerns, Observations and Findinas LER 96-049-01 had identified 976 deviations of minimum separation distances between a Class 1E and a non-Class 1E cable in the cable spreading and instrument rack rooms. As of November 12,1997, the licensee indicated that about 966 noncompliant items have been corrected through "re-training" (i.e., redundant cable trains tie-wrapped to minimum separation distances) of the cables, and repair of Sil-temp protective wrap The inspector conducted numerous field walkdowns in the various plant areas, e.g., East and West switchgear rooms, cable tunnels, diesel generator room "A", ESF rooms "A" and
"B", chiller room, charging pump room, auxiliary and hydrogen recombiner buildings, to assess whether the implementation of cable-wrap installations and cable tie-wrap arrangements are in compliance with separation requirements. The cable-wrap and cable tie-wrap installations were implemented to address the corrective actions for ACR/CRs M3-97-0543, M3-97-0975, M3-97-1351, M3 97-1352, M3-97-1413, M3-97-1414, M3-97-1445, M3-97-1575, M3-97-1576, M3-97-1579, M3-97-1580, M3 97-1581, and M3-97-1631 through M3-97-1638. The inspector observed that the cable-wrap and cable tie-wrap installations on the affccted cables met the electrical separation requirements. As part of the licensee's ongoins progrcm for correcting electrical separation noncompliances, CRs on potential electrical separation violations observed during housekeeping walkdowns have been initiated for immediate corrective action. For example, CRs M3-97-4200 and M3-97-4204 were initiated for corrective actions to address electrical separation problems with camera cord and temporary power cables in general plant areas. The inspector considered these ongoing activities to address the electrical separation problems to be acceptabl _ _ _ _ . __ _
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' LER 96 015-05 identified additional MCR~ panels where electrical . separation- 'i noncompliances were found; As of November 24,1997, the licensee indicated that 51
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. separation barriers had been installed in the various _MCR panels to correct the '
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noncompliances.' The installation of another 10 separation barriers is being performed prior to plant startup' to correct all of the identified electrical separation problems in MCR panels.- The inspector conducted several field walkdowns of the MCR panels, e.g., MCB-MB1, 1 MCB-MB3, MCB-MB5, ventilation panel VP1, and post accident sample panel, to verify the , actualinstallation of separation barriers and tie wraps on the Class 1E cable wiring Iri thei ,
- panels.- The licensee also conducted additional self assessments to evaluate the >
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- effectiveness of the tie wrap installations to maintain the electrical separation requirements '
. between Class 'E cable bundles. CRs M3 97-3440 and M3-97-3443 documented a few . cases of tie-wrap restraints which became ineffective due to movement of cable bundles
~! !after routine inspections. As a result of the self-identified findings, the cable bundles were
[ i rerouted to pruvide additional margin above the minimum acceptable distance. Additional: 3 h Ewalkdowns in the MCR panels were also performed to search for items which could ?
< become discrepancies at s'later date. . This allows proper restraints to be promptly : < implemented.- The inspector considered theae corrective actions for electrical separation noncompliances in MCR panels to be acceptabl .The licensee's training program and revision of applicable work planning procedures to ' enhance electrical separation inspections was addressed in NRC IR 97-202. The licensee
' has developed training aids to emphasize the implications due to electrical separation . ' violations, and the importance of attention to detail when performing installations of
- separation barriers and tie wraps. The enhancement of Engineering Specification SP-EE--
l 076 to include specific electrical separation inspection attributes was addressed in NRC IR
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L 97-203. The inspector has no new concerns in these arcas, Conclusions
. = Licensee corrective actions to address the electrical separation noncompliances in the MCR
> panels and other general plant areas were determined to be acceptable. The installation of : separation barriers and tie-wraps on Class 1E cable wiring in MCR panels met the electrical separation requirements. Most of the corrective actions on the noncompliant items in the other plant areas (e.g., cable spreading rooms) have been completed, and field walkdowns
- have verified tnat separation requirements between Class 1E and non Class 1E cables were met. All remeining activities are scheduled for completion prior to startup. Previous
inspections and updates of SIL item 57, along with discussions of the licensee's electrical -; separation program, have been documented in inspection reports 50-423/97-202 and 97- * l 203. L Since the licensee has a proactive program to identify end correct electrical ' '
' separation noncompliances at Unit 3, and neither this laspection, nor previous inspections , . have identified significant problems with the licensee corrective actions, SIL ltem 57,
' including all sub-items, is considered closed in addition, LER: 50-423/96 49, 96-15-05, and 96-45 are closed.
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E2.2 (Closed $ Unresolved item 50-423/93-07-07- Diesel Generator Fuel Storage Caoncitv fundare - SIL ltam 781 Insoection Scoom (92903) In inspection Report 50-423/93-07, issues wsre raised regarding differences between the emergency diesel generator (EDG) fuel oil storage tank capacity, as described in the NRC Safety Evaluation Report (SER) (NUREG-1031), and more recent ana'yses that take into account load changes and more occurate calculations. By letter dated October 17,1994, the staff issued Amendment Number 97 to the Millstone Unit 3 Operating License. The attached safety evoluation documented certain licensee commitments with regard to the guidance for ordering EDG fuel oil, recommendations for load shedding options, and procedural controls for cross-connecting the independent train fuel oil tanks and powering the opposite train fuel oil transfer pumps. The licensee's Emergency Plan Implementing Procedure (EPIP) was documented to be the source of such guidance. In IR 50 423/96-05, the staff updated the status of this issue and stated that the item would remain open pending further discussion with the licensee. Specifically, the staff stated that while the appropriate prncedural direction exists for performing all necessary design and operational steps to extend the duration of the available EDG fuel oil supply, it was unclear whether the EPIP, as committed, provided the necessary guidance to assure that such activities would be performed in a timely manner, Observations and Findings During this inspection period, the inspector reviewed the scfety evaluation associated with Amendment Number 97, procedure EPlP 4400 (Revision 5), the applicable operating procedures (ops 3346A & B), and calculation P(T) 1195, Rev.1. Procedure EPIP 4400 contains actions performed for lors of offsite power (LOP) or loss of coolant accident (LOCA). The procedure requires the licensee to place an order for emergency diesel generator fuel within 4 hours of a LOP or LOCA event, specifying that the fuel be delivered within 24 hours. This is consistent with the assumptions in calculation P(T)-1195 in that the calculation assumes that for the first eight hours of the accident for both postulated scenarios these loads are unchanged from the normal response to the accident. After eight hours, operators can take action and reduce the loads on both EDGs. Procedure EPIP 4400 also requires that the assistant director for technical support (ADTS) request that the manager of technical support (MTS) provide load reduction recommendations (1) within 24 hours of LOP or LOCA, or (2) if fuel oil cannot be delivered within the specified tim Therefore, if the licensee has indications that fuel oil cannot be delivered within 24 hours, the MTS will refer to the applicable procedures being used and make load reduction recommendations. This is consistent with the comrnitments the licensee made and the NRC found acceptable in the safety evaluation associated with Amendment Number 9 Based on the license 3's commitments regarding procedural commitments and the load shedding analysis, the NRC stated that Millstone Unit 3 meets the intent of the guidance described in ANSI N1951976 and was therefore, acceptable. The inspector reviewe6 operating procedures (ops) 3346A & B and confirmed that the guidance for cross-connecting the independent train fuel oil tanks and powering the opposite train fuel oil transfer pumps was contained in the procedure . . . . . . - .. ,
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The inspector determined that the licensee's procedures provide adequate guidnce and fulfill their commitments associated with Amendment Number 97. Therefore, )ne basis forL _ the staff's conclusions in the safety evaluation for Amendment Number 97 remain valid and the requirements for EDG fuel oil stored at Millstone Unit 3 meet the intent of the guidance described in ANSI N195197 Conclusions The inspector concluded that EPIP 4400 and ops 3346A & B contain adequate guidance to ensure that the licensee 'will have adequate and reliable fuel oilinventory in the storage tanks for seven days of continuous EDG operation following a LOP or LOCA at Millstone Unit 3. Based on these findings, URI 50 423/93-07-07 is considered closed: SIL 'e mn 78 is hereby update . U3 E7 Quality Assurance in Engineering Activities ;; E7.1 - IUndatal eel 96-201-28: Station Blackout (SBO) Audit (Undata - SIL ltam 371 Innoection Scone (37550) The inspectors reviewed the actions taken by the licensee in response to an NRC finding that appropriate corrective action had not been taken to resolve findings identified during a third party evaluation of the station blackout progra Observations and Findinos In 1996, an NRC inspection team identified that the licensee had not implemented corrective actions for three findings related to inadequacies in the SBO battery sizing calculation, the lack of SBO diesel generator maintenance procedures, and inconsistencies in the identification of SBO containment isolation valves. These findings remained open more than 18 months after their identificatio ,
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Batterv Calculation The licensee performed calculation SBO-COPE-1440 E3, " Battery Size Calculation for Eight Hour Station Blackout for Millstone Unit 3," to verify that the safety-related station batteries have adequate capacity so that at the end of an assumed 8 hour station blackout there would be sufficient voltage available to operate equipment necessary to restore power to the safety buses from the EDG or offsite power. Specifically, the calculation-included a verification that adequate voltage would be available to start the EDG, flash.the generator field and close the EDG output breaker or to close the reserve station service -
. transformer output breaker.- The inspector noted that this calculation verifies the coping capability for both safety related batteries. However, during a station blackout condition the alternate AC power source, the station blackout diesel generator, would be available within one hour of the loss of AC power. The SBO diesel generator would be aligned to power one of the battery chargers resulting in a fully charged battery at the end of the
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.I 4 - station blackout. This provides additional assurance' that adequate DC power will b3 Lavailable to support the~ restoration of AC power from the EDG or_ offsite power sourc i Maintenanca Proceduras
: The licensee issued procedures MP'3721 AR, "SBO Diesel Refue! Outage Preventive -I
- Maintenance,"_ MP 3721 AA, ."SBO Diesel 3 to 4_ Year Required Maintenance," and MP 3721 AF, "SBO Diesel Generator Thermostatic Valve Maintenance," to address the ,
: performance of preventive maintenance. Procedures for the six year and twelve year - i
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maintenance have not been issued. However, since the SBO diesel was installed in 1993, the procedures are not yet required, and action requests have been generated to track the l completion of these procedures. The inspector also noted that, although there was a lack ,
.of station maintenance procedures in the past, preventive maintenance was performed -
utilizing vendor procedures and with the ~ assistance of the diesel generator vendor ,
: ; representativ .
Containment laolation Valvan s The licensee performed engineering evaluation M3-EV 970251, " Containment Isolation- ' Valve Evaluation for MP3 SBO Event," to improve the docenentation of the ability _ to - provide containment isolation during a station blackout condition. The evaluation used the methodology provided in NRC Regulatory Guide 1.155, " Station Blackout," and NUMARC 87-00, " Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors." , , , The inspector reviewed this evaluation and found it to be thorough with the' exception that it did not document that there was the capability for local operation of valves 3RSS'MOV23A, B, C, & D to provide isolation of the penetrations to the containment sump. lThis item was discussed.with the_ responsible engineer who agreed to provide this information in the final version of +he evaluatio c.- Conclusions -
-The inspectors reviewed the associated engineering calculations and evaluations, and diesel generator maintenance procedures. The inspectors also discussed these issues with the r responsible engineers and performed an in-plant inspection of the SBO diesel generator and-.
: support equipment. The licensee's evaluation of these issues was found to be appropriate's and no deficiencies were noted during the walkdown. The material condition of the SBO diesel generator was excellen The inspector concluded that the licensee provided appropriate technical resolution of these issues. : However, eel 96-201-28 remains open pending final NRC enforcement considerations. - SIL ltem 37 is also hereby updated by review of the licensee's corrective : actions to this eel; and additionally with respect to eel 96-201-29. This eel also remains - .
4 _open pending further_ NRC enforcement, but the technical issues associated with this item _
, have been closed, as is documented in Section U2 E8.3 of this inspection repor l
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54 o E7.2 ' Final Safety Analysis Report (FSAR) Adannaev ft = ELM b= 21 -
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. By letters dated July 1 and August 28,1997, the licensee submitted Revision 10 and - Addendum 1'to Revision 10 to the FSAR.: The inspector reviewed the list of changes made , and selected 11 for further review. The inspector also reviewed Nuclear Group Procedure '
(NGP) 4.03, " Changes and Updates to FSAR for Operating Nuclear Power Plants," which is i .
the licensee's primary procedure to ensure that the FSAR is properly maintaine . e Ohaarvations and Findinos Title 10 of the Code of Federal Regulations (10 CFR) Section 50.59 allows licensees to _ O imake changes in the facility or to the procedures as described in the FSAR without prior m Commission approval, provided the proposed change does not involve a change in the TS cj Lincorporated in the license or an unreviewed safety question (USO). The criterion for - , 1 requiring a 10 CFR 50.59 safety evaluation for a change in the facility (or procedure) is that 4~
"a change in the f acility or procedures as described in the safety analysis report" be -
involved. This criterion means that a change in a structure, system, or component (SSC) or
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a procedure requires a 10 CFR 50.59 safety evaluation only if the following statements are , both true: the SSC (or procedure) being changed is described in the most recently updated FSAR submitted to the NRC in accordance with 10 CFR 50.71(e), and the FSAR , description of the SSC (or procedure) being changed would be affected by the change.
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- Procedure NGP 4.03 establishes the licensee's requirements, responsibilities, and U .. instructions for processing and approving changes to the FSAR. A FSAR change request (FSARCR) is the primary form the licensee uses to document a proposed intent or non- ' intent change to the plant. The licensee defines an intent change as a change to Information such as a TS limit, responsibility, numerical value, design bases, system description, etc. A non-intent change is defit.ed as a correction to spelling, typographics, i . punctuation, grammar, or to provide clarification. Procedure NGP 4.03 states that any ' change to the FSAR requires a safety evaluation, or a 10 CFR 50.59 safety evaluation 4 P screening form to ensure that the basis on which the operating license was issued is not invalidated. Procedure NGP 3.12, " Safety Evaluations," contains the guidance and screening form to determine whether a 10 CFR 50.59 safety evaluation is required. The-Inspector reviewed both NGP 3.12 and 4.03 and concluded that they contain adequate . guidance to make.the determinatio The inspector reviewed the FSARCRs to ensure that a proper safety evaluation (10 CFR " 50.59 evaluation) was completed where appropriate, that the licensee adequately ,
addressed the three questions in'10 CFR 50.59, and that the licensee followed NGP 3.12 =
- and 4.03 guidance. For the FSARCRs reviewed, the inspector determined that the licensee : adequately addressed 10 CFR 50.59 for the intent changes to the FSAR, and that the t
s - Lclassification of non-intent changes was appropriate. The' inspector determined that each
~ : specific intent change was properly addressed in the 10 CFR 50.59 safety evaluation and, ' therefore, no USQs were ;dentified. -The licensee currently plans to submit additional-
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addenda to Revision 10 to the FSAR, therefore the inspector will review additional FSARCRs following these submittals. Therefore, SIL ltem 2 will remain ope The inspector noted that by letter dated April 16,1997, the NRC requested that the clicensee submit, no later than 14 days prior to the Commission meeting for each individual - unit restart, what actions have been taken to ensure that future operation of the unit will be conducted in accordance with the license, regulations, and the FSAR. in a letter dated _ October 21,1997, the licensee stated that the response will be submitted after completion
. of each unit's ongoing CMP, but not later than 14 days prior to the Commission meetin This submittal will be the final licensee determination that the FSAR is a:: curate and that i-future ope 1tions will be conducted in accordance with the FSAR, license, and regulation Conclusions The inspector. concluded that NGP 3.12 and 4.03 contain adequate guidance to ensure that . :the FSAR is properly maintained. However, continued review of future FSARCRs which resulted from modifications and changes made during the current outage, review of the -
FSAR during future NRC team inspections, and review of the FSAR by the independent contractors is necessary, in part, prior to closing this issue. Thetafore, SIL ltem 2 will remain open and is hereby update U3 E8 Miscellaneous Engineering issues - E (Undate) ACR 10780: (Closed) ACR 10774: Turbine Driven Auxiliarv Feedwater desion concerns (Undate - SIL ltam 111 insnaction Scone (92903) The closure of the Turbine Driven Auxiliary Feedwater pump (TDAFW) 3FWA*P2 discharge valves 3FWA* HV36A,B,C,D at power lovels less than 10 % was identified as a possible violation of TS 3.7.1.2 which states that "At least three independent steam generator auxiliary feed-water pumps and associated flow paths shall be operable." The 3FWA*HV36A,B,C D valves were closed at power levels below 10% because the TDAFW
- pump discharge piping was classified as moderate energy piping in th. MP3 FSA However during normal plant operation a portion of the TDAFW pump discharge piping could be subject to high pressure discharge from the Motor Driven Auxiliary Feedwater (MDAFW) pumps during startup and shutdown evolutions. Therefore, this TDAFW discharge piping should have been classified as High Energy Line Break (HELB) piping and i was not. The closure of TDAFW pump discharge valves was reported in ACR 10780 and related aspects were also cited by the NRC in Eels 96-20104 and 0 In addition, it was discovered that the Auxiliary Feedwater valves 3FWA*HV36A,B,C,D would not remain closed when exposed to a differential back pressure greater than 5 to 7 psig in possible violation of 10 CFR 50, Appendix A, General Design Criteria (GDC) 57 requirements. These valves were not able to isolate reverse flow (flow out of the containment) at a 45 psig containment design pressure. The inspector reviewed the t
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corrective actions taken to correct the deficiencies noted in the two ACRs. The Eels will be addressed in separate review Ohservation and F"ndinos The inspector reviewed ACR 10780 and the associated documentation and engineering drawings. The options originally considered by the licensee to correct the lack of HELB qualification of the discharge line were: 1) install the required barriers and make other changes required to qualify the line as a HELB fluid system line: 2) request a TS change allowing closure of the discharge valves 3FWA*HV36A-D when below 10% power, and 3) develop an engineering justification that the TDAFW pump discharge valve could be closed at power levels less that 10% without making a request to change the TS. The initial documenta* ion reviewed by the inspector was based on the licensee's objective of justifying that the TDAFW pump discharge valve could be closed without a change in the TS. As a fall-back position, the licensee would request a TS change to close the TDAFW pump discharge valve at power levels less than 10% power. However as described in a NU-NRC letter dated July 14,1997 the licensee will no longer use the AFW system during startup and shutdowns. Furthermore, according to the licensee system engineer, the licensee is no longer planning to close the TDAFW pump discharge valve at power levels below 10% and is now in the process of determining the requirements necessary to qualify the TDAFW pump discharge line to HELB requirements. The final evaluation of ACR 10780 will be delayed until the licensee completes the HELB evaluatio The inspector reviewed ACR 10774 along with associated documentation.and engineering drawings. ACR 10774 refers to ACR 12215 where the details of the modification to valves 3FWA*36A,B,C,D are described. The AFW pump discharge valves 3FWA*36A,B,C,D would not remain c'osed when exposed to a differential back pressure greater than 5 to 7 psig. These valvss are 3 inch, normally open, solenoid-operated, modulating globe valves, which have now been modified to isolate reverse flow up to 1355 psid differential pressure. The inspector reviewed the following: Modify Target Rock Solenoid Valves 3FWA*HV36A-D; DCR M3-9605 Rev. O and Safety Evaluation number M3-96059. These describe how the valves have been successfully modified and now await final testing during Mode 3. The inspector also reviewed the valve drawings showing the new configuration and compared the environmental qualification accident conditions with the specifications for the valve seats. The inspector reviewed the documentation that
- showed that the valves, in their new configuration, had passed their seat leakage test. The inspector observed the modifie'i valves during a walkdown of the TDAFW system. This inforrnation is acceptable to close ACR 1077 Conclusions AFW pump discharge valves 3FWA*36A,B,C,D have been appropriately modified and ACR 10774 is closed. The licensee has stated an intent to make the pipe lines of interest HELB qualified. Calculations have been completed showing that the pipe lines in question are (with out changes) HELB qualified. Thesa calculations have not completed the approval cycle. When calculations showing the lines are HELB qualified are approved, ACR 10780 can then be closed. Based upon these reviews, in conjunction with the prior inspection of
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urvesolved item 96-201-40 in inspection report 50-423/97 202, SIL ltem 11 is _hereby . update , E8.2 " ACR M3-96-0685 Thermal Relief Valve Sejpoints (Undate Ellitem 58) , insnection Scone 192903) The Reactor Plant Component Cooling System (CCP) Thermal Relief Valve pressure setpoints were not in agreement with the piping design pressures shown on the Lin Designation Tables {LDTs). The purpose of these thermal relief valves in each sys!em is to-provide a pressure relief mecharism should portions of the system be valved shut and continue to receive heat, causing the fluid to expand and pressurize the system. The original, vendor supplied, pressure calculat;ons failed to account for the elevation differences of system components. The elevation differences result in static head '
' ' differences which in rnost cases are additive to the design pressure of the system , _
component. To determine the system design pressure, the relief valve set point cnd the , low point in the system pressure were calculated for 52 sub-systems within CCP. The calculation for each relief valve setpoint was made by noting the pressure difference caused by elevation differences between the relief valve and the component and then = adding this pressure difference to the manuf acturer's component design pressure. The pressure at the lowest point of the system was calculated by noting the pressure difference - caused by the difference between the elevation of the relief valve and the of ( tion of the system low point then adding thir elevation-difference pressure to the relief w.se set point pressure. This new low point, calculated, system pressure was then declared to be the
"new sub system design pressure." Relief valve setpoints were reset to the new calculated
- set pressures. The LDTs will be changed to reflect the new design pressures. The system components had previously been subjected to a hydrostatic test of 125% of the original
" design" pressur Observations and Findinas
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The inspector reviewed ACR M3-96-0685, calculation 97-ENG-01454-M3 Rev. O, and other associated engineering drawings and documents. The calculated relief valve setpoint pressure for each valve was reviewed by the inspector and compared with the actual relief valve setpoint pressure. The calculated pressures agreed with the actual relief valve setpoint pressures. The drawings associated with the calculations were found to have several ininor inaccuracies which did not affect the setpoint calculations or the new design pressures. These were corrected. The inspector compared the newly calculated design pressure, as tabulated in 97-ENG-01454-M3, with the former design pressures. The new design pressure exceeded the old pressure by amounts ranging from 5 to 55 psi Raising the design pressures implies a need for new hydrostatic tests of the sub-systems at .- 125% of the new design pressure,in accordance with ASME Code Section 11,- Article '
'lWC-5000, System Pressure T ests. Article IWC-5000 calls for a system hydrostatic pressure test for each system or portions of systems and for altered portions of systems.
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58 The licensee originally cited ASME Code Case N-416, dealing with repair and replacement, as allowing the postponement of hydrostatic tests, until the next regularly scheduled system hydrostatic test. However, this situation is a design change and not a repair / replacement, so the code case would not appear to apply and the requirements of Article IWC 5000 should be met, Conclusions This item has been acceptably addressed by the licensee with the exception of the need for a hydrostatic test of portions of the CCP system that had not been previously subjected to testing at 125% of the new design pressure. ACR M3-96-0557 regarding a similar issue was inspected, closed, and documented in IR 50-423/97-02, with the conduct of the required hydrostatic testing. Pending completion of such hydrostatic testing and acceptance of the results, or additional licensee justification for the deferral of this testing, ACR M3 96-0685 remains open. SIL ltem 58 is hereby update E eel 50-423/96 0916: ACR M3 96-0718: Anelvsis of Solenoid Ooerated Valves Fafure Modes due to Maximum Ooeratino Pressure Differential (MOPD) (Undate - Sllitem 60) insoection Scone (92903) Responding to NRC Generic Letter 91-15, which references NUREG-1275, the licensee inspected Solenoid Operated Valves (SOVs) which control air pressure to air operated valves (AOVs). The licensee initially reviewed the SLVs in the air control system and determined that there were no issues. NRC IR 50-423/96-09 determined that the licensee's review of the SOVs and their MOPD design requirements were inadequate. The concern was that the SOVs could be subjected to a maximum operating pressure differential (MOPD) which was greater than the design MOPD. Experience from other f acilities as described in NUREG-1275, Vol.6 indicated that the higher system pressure could cause the SOV to fail as is and not in the fail safe mode, in addition, the application of full pressure can cause the unenergized valve to lif t or open. The licensee had originally believed that the SOVs and the associated air regulators were purchased as a qualified safety-grade unit. The f ailure to establish design controls to verify the adequacy of the SOV design to operate properly when subject to fullinstrument air pressure was cited as an apparent violation of the requirements of 10 CFR 50, Appendix B, Criterion Ill, " Design Controls" in IR 50-423/96-0 The second review of Unit 3 SOVs performed by the licensee detailed their location, their MOPD, purchase specifications and a review to determine if the SOVs were safety relate Forty eight SOVs in both safety and non safety systems were found with a design MOPD of less than 110 psig, Observations and Findinos The inspector reviewed eel 96-09-16, M3-96-0718, and other associated engineering drawings and documents. Many SOVs found in the system had a typical design MOPD of
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60 to 75 psig and could have been potentially subjected to the air operating pressure of 110 psig. These SOVs are used to operate larger ADVs, most of which are safety relate The SOVs are provided air by an air system through regulators, neither of which is safety related. The relief valves in the air supply system are set at 'i25 psig, while the air regulators delivering air to the SOVs are set to deliver air at a maximum of 110 psig. The air regulators are designed for a maximum air inlet pressure of 250 psi Two separate walkdowns performed by licensee engineering and maintenance personnel determined the quantity and identification of all SOV installation details. The data coliection was performed to an approved procedure. Databases of information collected for safety related and non-safety related SOVs were created. Design documentation was changed, where required, to reflect the data collected on the SOVs. Of the 48 identified valves, seven were analyzed and determined to serve non-cafety related AOVs and level control valves (LCVs). Thus, they were kept as Category 1 only for electrical separation and pressure boundary purposes. MOPD was thus not a concern and these seven valves were not replacd. The inspector reviewed Material Equipmerit Parts List (MEPL) evaluations for these valves and noted that the evaluations appeared proper. To date 39 of the 41 remaining safety related valves have been replaced with new SOVs with a MOPD of 115 psig. Two remain to be replaced before startu To address preventive actions, Station Procedure DC 18 "NRC Communications", Revision 0, Change 1, was written to implement a process to ensure that NRC correspondence is reviewed for applicability to MP3 in a timely manner. Section 1.2 addresses processing of incoming correspondence and Attachment 5 tracks NRC correspondence receipt and distribution. A CR is to be generated by the licensee for items requiring a response with corresponding individual Action Requests generated to track each item to completion, Conclusions Thirty nine of the 41 SOVs have been replaced, two more SOVs remain to be installed and are scheduled for replacement prior to plant startup. This issue remains open pending replacement of the last two SOVs. SIL ltem 60 is hereby update E8.4 (Undate) eel 98-201-35: Desion Control Process Review - Unenalvred Restricting Orifice Installed in Service Water Svstem (Update - SIL ltem 79) Insoection Scone (929031 An unanalyzed restricting orifice was discovered in a vent line. This orifice communicated with two systems; the service water system and the main steam condenser cooling water system (circulating. water system). Both systems used the same vent line where the unanalyzed orifice wss installed. A second restricting orifice (previously analyzed) existed in the service water system. The two orifices are in series with each other. The orifice in
- the service water system had been previously analyzed to determine if it was adequate to allow enough air into the service water system to prevent water hammer and rejoining forces due to pump startup. Large elevation differences in the service water system caused column separation and rejoining phenomenon to be postulated during a loss of
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offsite power and pump restart sequence. The licensee's efforts to reduce the predicted water hammar loads included installing an open vent system at the highest system elevation that allowed air to enter the vent whenever the normally low system pressure dropped below atmospheric conditions. A restricting orifice was required in the SW line to limit the amount of water that would bypass the control building air conditioning coolers during normal operations, while allowing sufficient air volume to refill the SW system during the loss of offsite power sequence. The introduction of air into the service water system cushions the cclumn rejoining forces that occur when a service pump restarts. The vent line system allowed excess air to be introduced into the Main Steam Condenser Circulating Water System and prevented a vacuum from being drawn to prime the Main Steam Condenser cooling water boxes. The initial unanalyzed orifice was introduced into the vent system to overcome this inability to prime by reducing the air flow into the condenser cooling lines and allowing the establishment of a proper vacuu The unanalyzed orifice had been installed without documenting the installation and without entering the change into the Design Basis Documentation Package (DBDP) update process as required. As a result of the failure to include this new second orifice into the DBDP, the effect of this new orifice was not considered in the original water hammer analysis performed to size the first restricting orifice in the SW system. The addition of this new restricting orifice also invalidated the startup test results which showed that SW system column rejoining forms and water hammer forces were adequately mitigate Observations and Findings The inspector reviewed ACR 14021, ACR M3 96-0923, and eel 201-96-35 along with associated documentation and engineering drawings. The inspector reviewed the engineering calculations which, in an iterative fashion, calculated the turbulent flow rates of air through the unanalyzed square edge orifice in the 2 inch vent pipe common to both systems. The calculatior, determined that the unanalyzed orifice was improperly sized and that a one inch orifice was needed to allow the proper amount of air into the SW system through the SW orifice to satisfy the SW water hammer and column rejoining prevention requirements, and to also allow a proper vacuum to be drawn on the main condenser cooling system when required. The inspector reviewed the documentation which stated that the newly designed one inch orifice had been installed and tested in the common vent line with satisfactory results. The test consisted of running the Service Water system, starting and stopping the service water pumps, while observers stationed near the service water system observed and listened for water hammer. No water hammer was noted during the test. In addition, with the new one inch orifice installed, the main condenser cooling lines were emptied, then successfully primed after drawing a vacuum. The inspector walked down the modified service water system and vent line and observed no discrepancie Several actions were taken by the licensee to resolve the identified design control issu The corrective actions by the licensee were directed toward: 1) the Design Control Manual and supporting design control procedures 2) 10 CFR 50.59 safety evaluations: 3) FSAR revisions and maintenance; 4) configuration management: 5) training to improve regulatory
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61 -l awareness and engir,eering skills; and 6) corrective action initiatives'to ensure that design '
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The actions taken by the licensee to address the calculational discrepancies _are cortsidered~ ~!
, : acceptable.:The new calculations corrected the orifice' size and provided an adequate' basis :- r b - for providing for prevention of water hammer and rejoining actions while letting the :
condenser be started up after loss'of pump pressure._ The test of both systems verified the - calculations and demonstrated the absence of water hammer. The licensee's inadequate" design control issues are ongoing and are being addressed by an action item tracking'and' trending ' system (AITTS) assignment 97006285-01 and continue to be addressed, along
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with other design control issues, as part of the licensee response to the NRC 10 CFR 50.54.(f) request letter. 'Therefore, Sil. Item 79 is hereby updated. _ The technical aspects - :j
' of this issue have been determined to be adequate; however, eel 96-20135 remains open - H T pending ongoing NRC consideration of escalated enforcement actio ,
E8.5 Ranualification of Containment Panatrations Irha-8 - Ell item 481 , Inspection Scope (92903)
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, The inspector reviewed a vertical slice of the Millstone Unit 3 containment System.'
- : Ohnervations 'and Findinns ,
A potential design deficiency with 2.he containment penetrations 293 and Z94 had been previously identified by the licensee, as part of a CMP review process. These penetrations _ ,
(were originally designed for a temperature of .131 degrees Fahrenheit ('F). This temperature is appropriate for the safety injection scenario, but during residual hear removal (RHR) return to the RCS, the temperature could be as high has 350 degrees F. After a loss of coolant accident (LOCA) and during cooldown when the RHR pumps take 9
- suction from the reactor sump, penetrations Z93 and Z94 can reach 350*F. -The following
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' actions were initiated: ,
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2:e L Adverse Condition Report (ACR) M3-96-0183 was written to initiate action, e- DCR M3 96069, " Revise the temperature of the SlH/CHS Piping / Components," was
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. Issue e- Calculation No. 96ENG-1281C3, Rev 0, "Contain: .ent _ Penetration 93 & 94 - __ ,
- Temperature Evaluation," _was performed, which re-qualified the penetrations to
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?350* Io- Safety Evaluation Reports E3-EV-97-0014 and S3-EV-97-0279 were writte '
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-Specifically, the inspector reviewed the licensee's closure package for ACR M3 96-0183, to indude an evaluation of the causal factor corrective action plan, assessment of the approved design change record ( supported by calculations and a safet) evaluation), and -
confirmation that the specified corrective measures were sJequate and satisfactorily implemented. This SIL item closeout evaluation also entailed a review of contractor (Stone and Webster) thermal analyses and an assessment of the licensee's reportability determination on thi Conclusion Review of this item indicates that all appropriate actions were taken, including re-qualification of the applicable containment penetrations. SIL ltem 46 is considered close E8.6 Boron Dilution Analvsis/Primarv Grade Water Flow Rate (Closed - SIL ltem 441 References: ACR 12116 LER 96 026-00 LER 97-048-00 ACR M3 96-0325 LER 96-026-01 CR M3-97-2539 LEP 96-026-02 Insnection Scone (37550) The inspectors reviewed licensee actions taken to resolve questions concerning the boron dilution analysis, Observations and Findinos in May 1996, the licensee initiated ACR 12116 to document that assumptions that were made during the boron dilution analysis may have been non-conservative. The specific concern, addressed by this ACR, was that the inverse count rate ratio assumed in the boron dilution analysis did not bound the plant specific data. Subsequent review by Westinghouse Electric Corporation, contracted by NNECO to perform the boron dilution analysis, determined that there was not a problem and that the assumptions made during the accident analysis bounded the plant specific data and that the current boron dilution analysis remained valid, in July 1996, the licensee initiated ACR M3 96-0325 to document that calculations performed to determine the maximum flow rate from the primary grade water system (PGS) pumps to the charging pumps may have been in error. The maximum available PGS flow rate to the charging pumps is an input to the boron dilution accident analysis. The boron dilution analyses in the FSAR was based on one PGS pump operating with the normal make-up flow path and assumes a maximum PGS flow of 150 gpm. The uncertainty existed because of modifications to the dilution flow paths and because of questions as to which flow paths were evaluated and what assumptions were made for how many PGS pumps were operated. Licensee Event Report 96-026-00 was submitted to the NRC on August 23,1996 to report this condition and included a corrective action to perform a detailed calculation to account for flow path modifications, evaluate the alterne'e dilute flow pain, and determine the maximum flow for one or two PGS pumps operatm l
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LER supplement 90-026-01 was submitted to the NRC on October 14,1996, following the completion of calculation 96 ENG 1284-M3, "MP3 Boron Dilution Flow Rates For One and Two PGS Pumps Cases For Normal Di!ute, Alternate Dilute and Borate / Blend Pathways."
The results of the 'ecent calculation determined that the PGS flow to the charging pumps would be 132.1 Opm with one PGS pump running and 142 gpm with two pumps running, in both cases the flows are bounded by the 150 gpm assumed in the analyse LER supplement 90-026-02 was submitted to the NRC on November 15,1990. The purpose of this supplement was to report that, at the time LER 90-026 01 was submitted, the referenced calculation had not been reviewed and approved. However, the results and conclus'ons did not change as a result of completing the review and approval process for the calculation. LER 90 020 02 also included the licensee's evaluation of programmatic aspects asscciated with this issue. Yhe licensee noted that the control of calculations and the review process to address the effect of modifications on the accident analysis have been improved. The FSAR is also being updated to provide additional detail relative to the boron dilution analysis, in August 1997, the licensee identifU that the original PGS pump impellers had been replaced during initial plant startup, iba original 7.0" diameter impellers were replaced with 7.5" diameter impellers. When performmg calculation 96 ENG 1284 M3, the licensee used the pump curves associated with the originalimpellers, resulting in calculated PGS flow rates that were non conservative. The licensee documented the issue on CR M3 97-2539 and an initial review by design engineering indicated that PGS flow may exceed the assumptions of the boron dilution accidsnt analysis. LER 97-48 00 was submitted to the NRC on September 5,1997, to report this condition, and at that time, the licenree committed to ensuring that the PGS flow rate would meet the boron dilution event analysis prior to entering Mode To resolve this latest issue, the licensee perform a flow test for the PGS pumps. The flow path was from the PGS pumps to tho bottom of the volume control tank to closely simulate the boron dilution flow path. The results of the flow test were then used as an input to calculation 97 ENG-01487M3, "Goron Dilution Flow Rates Based On Test Flow Data." The results of this calculation showed that the maximum flow rates for all cases analyzed, included both pumps operating simultaneously, would again be bounded by the 150 gpm flow assumed in the boron dilution analysis, Conclusions The inspector reviewed the associated documentation and discussed the issue with licensee engineers. The inspector found that the licensee had performed appropriate engineering evaluations to resolve the questions regarding the boron dilution analysi The inspector concluded that the (h.ensee actions appropriately addressed this istue. SIL ltem 44 anu LERs 96-026 00,96-026 01, SS-026 02 and 97-048-00 are close O
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E8.7 IQaned) IFl 50_423]S544-0G Potential Service Water Backwesh Pine Fregyjng lQQ1ad Sll item 771 a, jntoecilon Scone (375501 in January 199G, Millstone Unit 2 experienced freoring of the service water backwash piping. Without the capability to backwash the stralners, service water flow could be reduced or lost due to strainer plugging. A plant modification was implemented to eliminate the problem on Unit 2. The inspectors reviewed the licensee evaluation and actions taken to address this issue for Unit Dhsetvationa.nnd Findin23 The licensee evaluated this issuo for Unit 3 and, Lased on the following considerations and actions taken, concluded that Unit 3 was not susceptible to a loss of all seivice water due < to frecting:
* Each of the two Urit 3 service water trains has a strainer backwash flow path that is independent of the other train. Unit 2 had one common backwash header and a single frecre affected both service water train * The controls for the Unit 3 strainer blowdown valves have automatic timers that initiate a periodic browdown ir. dependent of the strainer differential pressure signal that initiates an automatic blowdown on a high differential pressure condition. The timed blowdown was originally set at to actuate every eight hours but now have been reset to four hours, if the flow path became partially blocked by ice, the blowdown flow would melt the ice. Periodic, manually initiated, blowdowns wer:
performed on Unit 2 (prior to implementing the modification) and were successfulin cleaung accumulated ic * A complete loss of service water due to ice buildup would require blowdown valves in both trains to experience seat leakage at a rate sufficient to form an ice plug but not so high that the leakage would continually keep the line thawe * The backwash piping is directly exposed to the environment only at the end of the piping run where it passes through the intake structure wall. The portion of the piping that is routed under the intake structure floor is protected from the environment on all sides by concrete wall * Unit 3 has never experiencta any ice plugging of either of the blowdown line * Each strainer, tivo per train, hos a differential pressure instrument that actuates an alarm that will alert the control room operators if strainer plugging occurs due to blockage of the blowdown lin . - . . . _ . -. - -- - . . , . - _ . ~ . - ..-. .-. . - - _ - - . _ - - . - . _ . - . - .--
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-e The operator logs have been revised to require that the operators visually verify that the blowdown path is free once per day by observing blowdown flo [
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The inspector concluded that the licensee has taken appropriate measures to address this ' issue. SIL hem 77 and IFl 50423/9544 06 are close !
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ly Plant Sunnort ,
(Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry Controls R Radwaste and Trantnortation Procram Insoection Scone 186750 & Tl 2515/1331 The inspector reviewed the licensee's programs for the processing, packaging and shipment of radwaste and the transportation of radioactive materials. Also reviewed were program modifications made to incorporate major rule changes contained in Title 49, Code of Federal Regulations (49 CFR). The inspector reviewed licensee documents, interviewed personnel, and made direct observations of licensee activities, Observations and Findinog Unit .1 The liquid waste processing systems at Unit 1 continue to be unable to support plant operations. Since the identification of . rious defects in this system in September 1995 (NRC Inspection Report No. 50 245/9b-s5), a e ' mediation project has been underway to address these defects, and return the radweste system to full operability. Since the Unit was shut down in October 1995, a limited radwaste processing system has been available to support a shutdown condition. The inspector reviewed the current status of the radwaste remediation project, with unit operations and engineering personnel, and toured the liquid radwaste processing f acilities as part of this inspectio In order to support unit operations, four key elements have been identified by the licensee as needing resolution. These are: (1) installation of the afteady purchased vendor demineralization system in the equipment drain system; (2) relocation of the temporary bag filtration system; (3) design review and modification of the HVAC system in lower level radwaste to ensure compliance with air balance parameters; and, (4) configuration contro The inspector reviewed and discussed, with unit personnel, each of these issues; and inspected the current condition of the f acilities and equipment in the liquid radwaste syste The items identified by the license appear to accurately reflect the equipment and processes needed to support operations, it is expected that the planned system will be able to provide a basic, functioning liquid radwaste processing capability, but with minimal flexibility. While other ilealgn enhancements such as the installation of a new filter sludge tank and upgraded adwaste control room would improve system flexibility, such inclusion in the licensee's plan is not specifically required to support unit operation The inspector also reviewed the licensee's management of radwaste at the unit. Corrective measures in this area were required to address the root cause of the radweste problems
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previously identified. Since September 1996, four different Unit 1 supervisors have been assigned '. e as radweste manager. The last three have all been assigned as the Fix it Now (FIN) Teni.dRadwaste Manager. Discussions with the incumbent manager indicate that he was aware of the previous problems identified in Unit 1 radwaste, and was being provided the appropriate support by senior unit and site management to correct the identified deficiencies. He also indicated that the remediation project, which is currently suspended due to a freeze on spending at the unit, will be resumed and completed prior to a restart of operation The inspector also reviewed the status of licensee commitments (Letter from F. Rothen, NNECO to H. Miller, NRC, dated October 20,1996) in which the licensee identified three elements (commitments) to address the redweste problems at Unit + Commitment 815894.1 addressed the remediation program discussed above, and committed to a completion dato prior to unit restar ' Commitment B15894.2 addressed providing all plant staff additional guidance on conveying complete and accurate information to the NRC. On December 2,1996, additional Guidance was provided via articles placed in the Unit 1 Newsletter and the NU NUCLEAR NEWS DAILY, entitled "importance of Providing Complete and Accurate Information to NRC."
+ Commitment B15894.3 indicated that key nuclear directors and officers would be provided with a copy of an investigative report commissioned by the licensee regarding management actions involving the Unit 1 radwaste facility. A redacted copy of the report was issued, and the inspector questioned several managers at the director level and higher and confirmed that the report had been provided to the Unit 2 The radweste processing program at Unit 2 continued to be effectively implemente Management of the program is the responsibility of the Assistant Operations Manager, and daily work 16 conducted by the Primary Equipment Operator - Radwaste. The inspector reviewed the current program status with both of these individuals and the system engineer for Unit 2 radweste. A comprehensive walkdown of the unit radweste facilities was also conducte Clear lines of responsibility and ownership for radweste have been established at Unit 2 for sevcral years, in general, the radwaste systems were being operated in accordance with the Unit FSAR, which was last revised in 1996. The inspector noted that the serated waste domineralizer was no longer in service, and had been replaced by a temporary 3-vessel demineralizer system, which had not yet been described in the FSAR. The Assistant Operations Manager indicated that a change to incorporate this modification into the FSAR was forthcoming, and that the unit planned to install a permanent header system for these demineralizers to aid in operatio _
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O O G8 Unit 3
- A lack of management oversite and responsibility for liquid radwaJte processing was previously identified (NRC Inspection Report 50-423/97 02) at Unit 3. During this inspection, a discussion with the newly assigned radwaste manager, together with i discussions with the Primary Equipment Operator Radwaste (PEO . Radwaste) and Radwaste System Engineer and tours of the radwaste facilities were conducted. The Chemistry Supervisor has been assigned responsibility for the management of the radwaste program, and the PEO. Radwaste has been placed under his administrative contro Within the unit, the radwaste facilities continued to be maintained in a very clean and radiologically safe condition. The inspector did note two temporary modifications made to -
the existing plant systems, with temporary filters being placed between the waste drain tanks in bot', the high-level and low level systems and their in plant primary filters. The low level system modification has been in place for several years now, and remains undersized for its purposes. The high level system modification was recently installed to address cementaceous dust ar.d fine debris entering the radweste system due to core boring operations occurring under the Unit 3 Containmen The inspector discussed two discrepancies in the unit FSAR regarding radwaste with the Chemistry /Radwaste Manager and system engineer. In one instance, the capacity of the low level waste drain tanks is listed at one value in paragraph 11.2.2.1 of the FSAR, and at another, in Table 11.2 2 of the FSAR. It was subsequently determined that this item had previously been identified by the system engineer as part of an FSAR review, and a Condition Report was issued to document the finding and track the issu' until resolutio The second NRC identified discrepancy involved the flow diagrams in Section 11.2 of the FSAR, which indicate a waste filter downstream of the waste demineralizer (Demineralizer #1)in the liquid waste system (LWS), and the descriptive text for the LWS found in Section 11.'t.2.1 of the FSAR, which does not mention this filter. The system engineer indicated that this issue would be documented and corrected in the FSA Site Health Physics ! The Waste Services Group is responsible for the processing of spent resin waste at Units 1 and 3, and the collection of spent filter cartridges, dry aciive waste, used laundry and potentially free-release trash from all three units. The Weste Services Group also packages and ships radioactive materials off site. As part of this inspection, a review of randomly selected radioactive material shipments was conducted by the inspector. Shipments selected originated in each of the three units, and included radwaste for disposal in Utah and South Carolina, contaminated laundry, laboratory samples and contaminated equipment. All shipments reviewed were determined to be in full compliance with all applicable regulations contained in 10 CFR Parts 20,61 and 71 and 49 CF The Waste Services Group also operates a dect ' amination facility located in the Unit 1 Solid Radwaste Building, col % cts and processes dry active wastes and contaminated laundry at the Millstone Fiedweste Reduction Facility (MRRF) and free releases clean materials through Warehouse #9. Work in all of these f acilities is also supported by health
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physics technicians from the Site Support HP group. This organization also conducts radiological surveys in support of the transportation of radioactive materials from the sit All survey documentation reviewed was in compliance with 10 CFR Parts 20 and 71 and 49 CFR. The inspector also reviewed licensee procedures and documentation and verified that the appropriate chrnges have been made to ensure compliance with the revisions to 49 CF Conclusions ; improvements were noted in the radwaste processing programs at all three units. The radioactive materials transportation and radweste disposal program continued to be effectively implemented. Clear lines of responsibility for radwaste management at all three units have now been established. All shipmr ts reviewed were determined to be in compliance with the applicable provisions of Titles 10 and 49 CFR. As a result of this - inspection, and the review of staff training and quality assurance implementation documented below, Unit 3 SIL ltem 35 is considered closed. Continued inspection of this area will be conducted on a routine basis in accordance with the guidance of the NRC Inspection Manual Chapter 2515 provisions for Core Inspection Program Procedures (i.e., IP 86750).
RI.2 Control of Locked Hioh Radiation Area Associated with Unit 2 Recenerative Heat Exchanant , a, jnggectlon Scope (71707) On November 19,1997, during a tour of the Unit 2 containment building, the inspector evaluated the adequacy of the licensee's control of the Technical Specification (TS) Locked High Radiation Area associated with the regenerative heat exchanger, Observations and FindlDas The regenerative heat exchanger is mounted vertically, spanning two levels of the - containment building and is located a few feet from the containment building wal Because the radiation levels in the vicinity of the heat exchanger are greater than 1000 mR/ hour, controls for a Technical Specification (TS) Locked High Radiation Area must be established. TS 0.12.2 requires that areas accessible to personnel with radiation levels greater than 1000 mR/Hr at 1E inches from the radiation source shall be provided with locked doors to prevent unauthorized entry. From the lower level ( 22 foot elevation), access to the heat exchanger is prevented by means of a locked door. On the upper level ( 3 foot 0 inch elevation), there is no convenient place to install a locked door so the licensee cocooned the heat exchanger with wire fencing to prevent access to radiation levels greater than 1000 mR/ hour. The inspector had three concerns associated with this physical barrie (1) On the upper level on the left side of the heat exchanger, there was an approximately two foot gap in between the wire foncing and tha containment building wall, whicl is large enough to allow personnel access. NRC Regulatory
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Guide 8.38, " Control of Access to High and Very High Radiation Areas in Nuclear Power Plants," states that an acceptable method of excluding personnel from areas with dose rates greater than 100 mR/ hour is to provide a substantial physical barrier (e.g., chain lirik fencing) that completely encloses the area and has no openings or portals. The inspector discussed this concern with the licensee who extended the wire fencing on the lef t side of the heat exchanger to eliminate any embiguity whether this two foot gap could allow personnel acces (2) On the upper level, on the outside and to the right of the wire fence cocoor, there was an approximately 3 foot by 3 foot opening at floor levelinat would allow a person to climb down approximately 10 feet into the TS Locked High Radiation Area in the lower level. NRC Regulatory Guide 8.38 also stetes that openings in physical barriers around a high radiatief area are not required to be controlled as entrances if
" exceptional measures" are needed to access them. Examples of areas that do r ot need to be controlled as entrances are the manway to a tank that has its cover bolted in place or an opening in a shleid wall that is physically difficult to access without a ladder or mobile platform. Based on this guidance, the inspector did not consider the 3 foot by 3 foot opening to be acceptable because an individual could readily climb down to the lower level without using any tools or ladder The licensee observed that " exceptional measures" would be required to access the lower level. These exceptional measures include climbing over the hand rail and performing a " precarious" decent of more than 10 feet which is not allowed by plant safety procedures, in addition, the licensee indicated that the individual would have to ignore the TS Locked High Radiation posting, which is discussed further belo Notwithstanding, the licensee agreed to immediately extend the wire fencing to the right of the heat exchanger to eliminate any ambiguity whether personnel could access the lower level via this openin (3) On the upper level, the licensee used yellow and magenta colored rope to hang a TS Locked High Rad!ation Area posting about 4 feet above the 3 foot by 3 foot opening described above. The licensee added the words "Below This Line" to the postin The licensee stated that this posting was added when HP Technicians also had concerns regarding possible access to the lower level TS Lock High Radiation Are This posting created a TS Locked High Radiation Area behind and "Below the Line" on the posting. The licensee found this posting to be acceptable because the radiation levels behind and below the posting on the upper level were less than 1000 mR/ hour. However, the inspector determined that control of this area must be consistent with the posting and that the rope and posting did not constitute a physical barrier to prevent unauthorized entry into this accessible area as required by -
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The NRC concluded that the foregoing deficiencies were of minor safet/ concern and are cnnsidered a non-*2J violation, The rope and pesting created a TS Locked High Radiation on the uppet leves having no physical barrier to prevent unautt orized entry into this ! accessible area. The licensee took prompt actim to extended the wire fencing to e!iminate , any ambiguity with this opening, as well as the 2 foot gap on the lef t side of the regenerative heat exchange ; R5 Staff Training and Qualification In Radiological Protection and Chemistry intoection Scone !86750) and Tl 2515/133 The inspectors reviewed the licensee's program for the training of workers in accordance j with NRC IE Bulletin 7919 and 49 CFR 172.70 Observations and Findinas i The inspector reviewed the technical training provided to workers involved in the handling and shipment of radioactive materials. The inspector examined the lesson plans, learning objectives and course materials related to the transportation training schedufod to commence on December 2,1997 for workers in the Waste Services, Quality Services and HP Support groups. This training is given on a three year basis as required by 49 CF The scope and depth of this training program appeared adequate to address all topics involved in the transport of radioactive materials from Millstone Station. The inspector also reviewed the training given to warehouse workers who occasionally handle limited quantities of radioactive materials. The scope and depth of this training was commensurate with the types of meterlats to be handle Personnel assigned to review and sign shipping and waste manifests were provideu vendor-supplied training as part of the licensee'e commitment made in response to NRC IE Bulletin .,
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7919. The inspector reviewed the course materials and learning objectives and determined that this training met the requirements for this type of instructio Conclusions The technical training program for personnelinvolved in the transportation of radioactive materials was very effective. Training was established commensurate with the level of radioactive materials handled and the scope of individual work as required by 49 CF ,
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R7 Quality Assurance in Radiological Protection and Chemistry Activities Insoection Scone (88750) and Tl 2515!133 The inspectors reviewed the licensee's program for the assurance of quality in waste processing and transportation of radioactive materials. The inspectors evaluated this program through the review of audits and surveillances conducted of licensee activitie Observations and Findinas The inspector reviewed the licensee's most recent Technical Specification required audit of the Process Control Program at all three units, together with documentation of Quality Surveillance reviews of radioactive materials shipments and self assessments conducted by the Waste Services Group. Audit MP-97 A04-02, " Process Control /Radwaste," dated May 30,1997 documents the findings and conclusions of the audit conducted in April 199 Five Condition Reports (CRs) were issued to document the findings contained in this repor . At the time of this inspection, Nuclear Oversite had not reviewed the responses to the CRn, and consequently all remained open. The inspector discussed the need for timely review and action on documented audit findings with the Audit manager who indicated that he viewed the f ailure to address the CR responses as unacceptable, Quality Surveillances are conducted on all packages of radioactive material shipped from Millstone Station. Dstalled check lists have been developed for the various types of radioactive material shipments made, and the completed documents are incorporated into the shipment record packages. Additionally, during 1997, the Waste Services Group began conducting periodic self assessments of their program areas. The inspector reviewed several of these assessments and concluded that they alded in improving the processing and shipment of radioactive materials, Conclusions The followup and closeout by Nuclear Oversite of issues identified during the April 1997 audit of the radwaste and process control programs at the site was weak. The conduct of self assessments and the level of involvement of Quality Surveillance in the radioactive materials transportation program was goo R8 Miscellaneous Radiological Protection and Chemistry issues R Previousiv identified itemi Violations (50 336/97 0109 and 50 245,50 336,50-423/97 0217): Failure to follow procedures / poor radiological worker practices. The inspector reviewed the licensee corrective action packages for these two violations as part of this inspection. An additional violation of a similar type was alsc issued as part of NRC Inspect on Report No. 97 20 These violations are therefore closed, and the effectiveness of corrective actions will be tracked under the violation contained in the later repor _ _ =_
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S8 Miscellaneous Se:urity and Safeguards issues S8.1 Protected Area Access Inspection Scope The inspector conducted a review to determine why an authorized individual had properly entered the protected area (PA) and not been logged into the PA by the security computer, Obmarvations and Findingg On October 8,1997, the NRC became aware that an authorized individual had entered the site PA In September 1997 and was not logged in on the security computer. Because the individual was not logged into the PA, when the individuallogged out, an alarm was _ generated and security officers responded, identified the individual, and had her contact the central alarm station. The individual stated that she had entered the protected area routinely and was unaware of the reason for the alar A regional security inspector reviewed all computer transactions for the month of September 1997 for the individual and determined that on one occasion, tbn individual ' , entered the PA and was not logged in by the security computer. When the individual exited the PA on that day, the exit transaction caused an alarm. The computer transaction log stated "T/S No Action" (T/S is the abbreviation for turnstile) at the time the individual entered the PA and " Key not in the PA" at the time the individual exited the PA. The " Key not in the PA" signal results in a response by security officers. The "T/S No Action" signal does not result in a response l, J security officer because it indicates that an authorized individual had initiated entry into the PA, but not completed the entry by passing through the turnstile into the P The inspector's review also disclosed that eight other authorized individuals properly entered the PA and were not logged in by the security computer during the same week that the individual that identified the problem entered. All of the individuals then caused an * alarm when exiting the PA. The inspector's review disclosed that the individuals were not properly logged into the PA because of a malfunction of a mechanical component on two of the entrance turnstiles. The malfunctioning component failed to activate a microswitch that would have sent a signal to the security computer that a successful entrance into the PA had occurred. The signal the security computer received was that an authorized entrance had been attempted but not completed; therefore, the individuals were not logged into the P Because of the gross number of transactions through the turnstiles daily (approximately 9200) and because alarms of this type can be caused by individuals incorrectly logging out of the PA, the f ailure rate of less than two per day, as a result of the mechanical malfunction, was not identified as a problem at that time. However, in mid-October, the mechanical failure rate on the turnstiles increased and the problem was identified. Both problem turnstilee have been rebuilt and mechanical failures of all turnuiles that result this type of problem are now tracked and trende '
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74 Conclusion The inspector's review concluded that authorized individuals had entered the PA without being logged in the security computer as a result of a mechanical malfunction. Testing of the system disclosed that only authorized personnel could gain access during this condition, therefore, no security vulnerability existe However, the inspector's review disclosed that the security computer indicated that the individual that identified this condition to the NRC was not properly logged into the PA by the security computer on September 10,1997, and the individual recalled that incident occurred on September 23,1997. The licensee is conducting further interviews and reviewing additional documentation to attempt to resolve this discrepancy. The NRC will review the licensee's final report when complete, tracking this issue as an inspector iollowup item (IFl 50 245;336:423/97 207-04).
F1 Control of Fire Protection Activities F Fire Protection Prooram . Unit 3 Review (Undate - SIL ltem 42) Insoection Scone 192904) At the time of the 1985 fire protection program inspection, (Inspection Report No. 50-423/85 53), procedure EOP 3509, titled " Fire Emergency," was in draft form and was not reviewed by the inspection team. This procedure addresses fires in areas other than those requiring alternative shutdown. During Inspection 50-423/97 84, the inspection team identified several open items which the licensee would need to complete prior to closing SIL 42: (1) functional testing of alternate shutdown capability; (2) procedures necessary to address technical requirements manual (TRM) surveillance requirements of post fire safe shutdown components; (3) in situ testing of charging purnps emergency ventilation fans (3HVR-FN18A/B); (4) verification by walkdown or other methods of the cable routing database to ensure that the database depicts the as installed configuration of the cables; (5) re implementation of safe shutdown requirements and commitments into emergency operating procedures by providing 32 separate attachments to EOP 3509 to address all of the fire area evaluations contained in the licensee's BTP 9.51 Compliance Report, in the current inspection, the inspector reviewed the status of the licensee's response to these open items, Observations and Findinog The first open item addresses functional testing of alternate shutdown capability, existence of documentation that the alternate or Auxiliary Shutdown Panel and its isolation transfer switch capability (the Fire Transfer Switch Panel) had over been functionally tested either during the original startup of Unit 3 or since that time, and the existence of a test procedure in effect to perform such testing. The licensee provided results (Test Procedure 3 INT 3000 Appendix 3014, " Remote Shutdown with Cooldown," Rev. O, 07/10/85) which indicated that the Auxiliary Shutdown Panel had been tested on 11/01/85 to meet the requirements of General Design Criterion 15, " Control Room." The test was performed in l
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accordance with EOP 3503, " Shutdown Outside Control Room," Rev. 1, 02/01/85, and EOP 3504, " Control Outside Control Room," Rev. 1, 08/14/85. The test was halted because of equipment malfunctions during the test. Since the test was designed to demonstrate compliance with GDC 19, neither a fire nor a concurrent loss of offsite power were postulated. Therefore, tM Fire Transfer Switch Panel was not tested during this test, nor were any local manual actions such as local starting of a diesel generator or valve operations which might be required to respond to a fire in the control room or charging pump cubicle which would require evacuation of the control room. The sound powered phone system, which would be assumed to be protected from the effects of the fire, was not available at the time of the test and was not considered to be required because offsite power was assumed to be available. Time lines indicating the allowable amount of time to perform all of the actions required for a control room or charging pump cubicle fire were presented in a letter to the NRC dated 07/01/85 and were accepted by the NRC under Supplement No. 4 to the MP3 Safety Evaluation Report, NUREG 1031, sub-paragraph 9.5.1.4, " Alternative Shutdown Capability," dated 11/85. A simulated walkdown of the alternate shutdown procedures was performed during the August,1985 NRC fire protection program inspection. Item 1 remains open pending demonstration of initial operab testing having been performed for allinstrumentation and controls required to respono to fires in areas requiring alternative shutdown capabilit The second open item concerns the existence of procedures necessary to address TRM, 3TRM 7.4, Section I, " Fire Related Safe Shutdown Components," surveillance requirements for post fire safe shutdown components and documentation that such components had been tested. In Condition Report M3 97 3182, corrective action item no. 5, the licensee committed to performing an initial test of the Fire Transfer Switch Panel (FTSP), emergency diesel generator "A", and FN 18A/B, as required by 3TRM 7.4-8, Section I, prior to entering Mode 3. A/R 96002527-02 (Schedule Reference 06UO2) was identified as tracking operating / surveillance procedure updates needed to meet this corrective action. TRM Table 7.4 7 of the referenced TRM section (Rev. 4, effective date 08/27/97) identified fire related safs shutdown components not associated with technical specifications. TRM Table 7.4-8 identified all of the safe shutdown components required for all fires, regardless of whether the fire required use of the alternate shutdown capability. 'The TRM section also specified - whether the component was to be demonstrated operable locally (SR1.a), at the local transfer switch or switchgear (SR1.b), at the Fire Transfer Switch Panel (FTSP) (SR1.c), at the Auxiliary Shutdown Panel (ASP) including the FTSP, if applicable (SR1.d), or from the Control Room (SR1.e). The fire related safe shutdown instrumentation and controls either already were or will be incorporated into procedures as discussed in the following paragraph. Additionally, the licensee committed to change the wording of 3TRM-7.4, Section I, page 37, " Surveillance," to indicate clearly that SR1.a, SR1.b, SR1.c, SR1.d, and SRI.e are not alternative methods of satisfying the surveillance requirement The Operations Department has revised 15 out of 20 procedures. Three new procedures have not been started yet. Other departments had six procedures in various stages of progress. The licensee provided SP 3673.4, " Auxiliary Shutdown Panel Operability Test," Revision 3,01/04/96, which indicated that the Auxiliary Shutdown Panel was subjected to routine surveillance testing at each refueling outage. For the Fire Transfer Switch Panel, the licensee was in the process of developing a separate surveillance procedure for the ..
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control functions on the panel. The instrumentation was being tested under the separate surveillances performed for the individual systema of the instrumentation present on the , panel. There was a separate surveillance procedure for the sound powered phones (SP i 3648.1, " Sound Powered Phone Function Test," Rev. 1, 01/16/95).
'herefoie, item 2 also remains open pending completion of procedures nocessary to address TRM surveillance requirements of post fire safe shutdown components and documentation that such components had been teste Items 1 and 2 were addressed previously In NRC Inspection Report 50-423/97-203. As noted in that report, the safety significance of the apparent lack of testing in the past cannot be assessed until the required tests are performed and the results evaluated. An unresolved item URI 50-423/97 203 011 was documented to identify the need for further NRC review of the final documents and the results of additional testing. The above discussion of items 1 and 2 in this current report constitute an update to URI 50-423/37-203-01 For the third item, a new test procedure is being developed for in-situ testing of emergency ventilation fans (3HVR FN18A/B), powered by a separate gasoline-driven electrical generator, to verify ventilation capacity for the charging pumps. Item 3 remains open pending NRC review of the new test procedure and the test results of the in situ testing of the portable emergency fans, required upon loss of charging pump cubicle ventilatio The fourth item is verification by walkdown or other methods of the cable routing database to ensure that the database depicts the as-installed configuration of the cables. The licensee had not yet initiated any actions to address thle concern. Item 4 remains open pending verification by walkdown or other methods of the cable routing database to ensure that the database depicts the as installed configuration of the cable The fifth item addresses re-implementation of safe shutdown requirements and commitments into emergency operating procedures by performing a major revision to EOP 3b09, " Fire Emergency," by providing 32 separate attachments to EOP 3509 to address all ! of the fire area evaluations contained in th'.: licensee's BTP 9.5-1 Compliance Repor Twenty-one procedures had been approved by the PORC and were expected to be issued by the Controlled Documents Library with an effective date of 12/18/97. The remaining l nine procedures were in various stages of preparation and review. Walkthroughs of ell of the 21 approved procedures h::d been performed and walkdowns will be conducted for the , remaining nine procedurer, prior to final approval. Item 5 remains open pending NRC review and walkdown upon comp'etion of the major revision to EOP 3509, " Fire Emergency," by providing 32 separate attachments to address all of the fire area evaluations contained in the licensee's BTP 9.5-1 Compliance Repor c, Conclusions While significant work has been performed by the licensee and progress made, all five items of SIL ltem 42 for Unit 3 remain open, as updated above. URI 50-423/97 203 011 has been updated and also remains ope ' i
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V. Mananoment Meetings X1 Exit Meeting Summary
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The inspectre a 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 presente X1.2 Final Safety Analysla Reoort 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 UFJAR commitments. All reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures and parameter While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The following inconsistencies were noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspectors, as documented in Sections U3.07.1 and R . s b.
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INSPECTION PROCEDURES USED j
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IP 37550: Engineering
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JP 37551: Onsite Engineering
IP 37001 10 CFR 50.59 Safety Evaluation Program
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IP 40500: - Licensee Self Assessments Related to Safety issues Innpections ,
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_ IP 62707: Maintenance Observations
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IP 71707: . - Plant Operations IP 86750: Solid Radioactive Waste Management and Transportation of Radioactive- , Materials
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IP 92700: - Onsite follow up of Written reports of Nonroutine Events at Power Reactor Facilities IP 92901: Folicw up Operations IP 92902: Follow up Maintenance
'lP 92903: Follow up Engineering IP 92904: - Follow up Plant Support Tl 2515/133- Implementation of Revised 49 CFR Parts 100-179 and 10 CFR Part 71 P
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened
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URI 50 245/97 207 01 U1.E EDG Lube Oil Sump Level URI E0 336/97 207 02 U2.0 Temporary Swapping of the Inservice : RBCCW Hx w/o Swapping SW URI 50 336/97 207-03 U2.M Temporary Loss of RBCCW IFl 50 245/336/423/97 207 04 S Protected Area Access
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Claard VIO 50 336/94-?.0102a,b,&c U2 E Plant Design Chances ; URI 50 336/96 0814 U2.E Startup Rate Trip ' VIO 60-423/94 24-01 U3.O MSIV Solenoid Valves URI 50-423/93 07 07 U3.E Diesel Generator Fuel Storage ! IFl 50 423/95 44 06 U3.E SW Backwash Freezing VIO 50 336/97 0109 R Radiation Protection ,, VIO 50 245/336/423/97 0217 R Radiation Protection Discussed eel 50 245/97-02-01 U 1.0 Condition Report Trending eel 50-306/97 0212 U2.M Inadequate Surveillance Test eel 50-423/96 20128 U3.E Station Blackout eel 60 336/423/96 20129 U2.E Trending NCR's VIO 50 423/97 202 08 U3.E Restart issues eel 50 423/96 20128 U3.E Station Blackout *
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eel 50-423/96 0916 U3.E Solenoid Operational Valves -
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eel 50-423/96 20135 U3.E Unanalyzed Restricting Orifice URI 50-423/97 20311 F Fire Protection Program The followino LERs were aiut., closed durino this insoection 50 336/96 41 50-423/96 42 U3.M Containment Fuel Drop Radmonitor 50 423/96-46 U3.M7 Containment Fuel Drop Radmonitor
'50 423/96 026,01, & 02 Boron Dilution .50-423/96 049, 96 15, 96-45 Electrical Separation LER Updated I
50-423/96 37 U3.M Spent Fuel Pool Coolin0 System >
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LIST OF ACRONYMS USED ACR(s) adverse condition report (s) ADTS Assistant Director of Technical Support AFW auxiliary feedwater AITTS action item trecking and trending system ALARA as low as reasonably achievable AOP(s) abnormal operating procedure (s) AOV(s) air operated valve (s) AWMT aerated waste monitor tank AWO(s) automated work order (s) BTP branch technical position CAERT corrective action effectiveness review team CBM condition based maintenance CCP reactor plant component cooling CFP Code of Federal Regulations CMP configutation management plan CNO Chief Nuclear Operetor CR(s) condition report (s) CRDR control room design review CWMT(s) clean water monitor tank (s) DBDP(s) design Lssis documentation package (s) DCN(s) design change notice (s) DCR design change record DDR(s) design deficiency report (s) EDG(s) emergency diesel generator (s) eel (s) escalated enforcement item (s) EOP(s) emergency operation procedure (s)
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EPIP(s) emergency plan implementing procedure (s) EQ environmental qualification ERG (s) emergency response guidelines (s) ESAS engineered safeguards actuation system ESF emergency safeguards f acility ESFAS emergency safety features actuation system FAC free available chlorine FME foreign material exclusion FSAR Fmal Safety Analysis Report FSARCR(s) Final Safety Analysis Report Change Request (s) FTSP fire transfer switch panel GDC- general design criterion / criteria GL Generic Letter GT gas turbine opm gallons per minute HELB high energy line break HVAC heating ventilation and air conditioning HX heat exchanger l&C Instrumentation & Control
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ICAVP Independent Corrective Action Verification Program IFl inspector follow item INPO Institute of Nuclear Power Operators IR(s) Inspection Reports (s) ISEG independent safety engineering group LCO limiting condition for operation LCV(s) local control valve (s) LDT(s) line designaticn table (s) LER(s) licensee event report (s) LNP loss of normal power LOCA loss of coolant accident LWS liquid waste system MCR main control room MDAFW motor-driven auxiliary feed water MEPL(s) material, equipment, and parts list (s) MOPD rnaximum operational pressure differential MRRF Millstone Radweste Reduction Facility MSIV main steam isolation valve MSR(s) moisture separator reheaters MTSC Manager, Technical Support Center NCR(s) nonconformance report (s) NEO nuclear engineering & operations NGP(s) nuclear guidance procedure (s) NI nuclear instrumentation NNECO Northeast Nuclear Energy Company NORVP nuclear oversight restart verification plan NRC Nurdear Regulatory Commission NRR Nu. . ear Reactor Regulation NSAB nuclear safety assessment board NSIC Nuclear Safety Information Center NTOL near term operating license NUMARC Nuclear Management and Resources Council NUREG Nuclear Regulation NUSCO Northeast Utilities Service Company OCA Office of Congressional Affairs OEDO Office of Executive Director for Operations OP(s) operating procedure (s) PA protected area PAO Public Aff airs Office PASS Post Accident Sampling System PDCR plant design change record PDR Public Document Room PEO plant equipment operator PGS primary grade water system PLC post loca cooling PORC plant operation review committee RBCCW reactor building closed cooling water
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RCG reactor coolant system i RFU refueling outage . RHit residual heat removal , RIE replacement item evaluation RO reactor operator , RSG recirculation spray system
- RWST refueling water storage tank SBO station blackout '
SER(s) safety evaluation report (s) SFP spent fuel pool " Sil significant item l ' SOV(s) solenold operated valvels) " SP(s) surveillance procedure (s) l SPDS safety parameter display system . SPO Special Projects Office , SPROC special procedure . SRO senior reactor operator l SS shift supervisor SSC(s) structures, systems, and component (s) i
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STA shif t technical advisor ' TDAFW turbine driven auxiliary feedwater TLD(s) thermoluminescent dosimeter (s) TMI Three Mile Island TRM Technical Requirements Manual
. TS(s) technical specification (s)
UFSAR updated final safety analysis report UIR(s) unresolved indication teort(s) URiis) unresolved item (s) . USO(s) unresolved safety question (s) VDU(s) video display unit (s) WEC_ Westinghouse ' WOG Westinghouse Owner's Group
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