IR 05000245/1998212
| ML20153H176 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 09/25/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20153H173 | List: |
| References | |
| 50-245-98-212, 50-336-98-212, 50-423-98-212, NUDOCS 9809300336 | |
| Download: ML20153H176 (70) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos.: 50-245 50-336 50-423 Report Nos.: 98-212 98-212 98-212 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
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Dates: -June 30,1998 - August 17,1998 Inspectors: T. A. Eastick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, 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. M. Brand, NRC Resident inspector, Seabrook
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J. T. Furia, Sr. Radiation Specialist, DRS i C. G. Cahill, Reactor Engineer, DRS P. P. Narbut, NMSS, NRC HQ R. E. Architzel, NRR, NRC HQ
E. J. Benner, NRR, NRC HQ N. J. Blumberg, PE, Region I T. A. Moslak, PE, Region I
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G.W. Morris, RE, Region i J. Higgins, NRC Contractor, BNL P. Bezier, NRC Contractor, BNL M. Subudhi, NRC Contractor, BNL J. Cadwell, NRC Contractor, BNL Approved by: Jacque P. Durr, Chief Inspection Branch Millstone inspection Directorate Region 1 0 $hkjh <
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TABLE OF CONTENTS l
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? AC U TIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv U1.1 Operations ..................................................1
, U101 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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U 1.li M aintenan ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 U1 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 l
l U 1.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 ;
U1 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 l
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U2.1 Operations ..................................................7 i
! U2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . . 8 U 2.ll M aint en a n ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 l U2 M1 Conduct of M aintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 U2 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . 9 l U 2.lli Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 U2 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 l U2 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 19 l
U3.1 Operations .................................................28 U3 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 U3 08 Miscellaneous Operations Issues (92700) . . . . . . . . . . . . . . . . . 32 U 3.Il M aintenan ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3 i
U3M1 Conduct of Mai~enance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 l U3 M8 Miscellaneous Maintenance Issues . . . . . . . . . . . . . . . . . . . . . . 38 U 3.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 9 U3 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 l
U3 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . 41 IV Mant Suppon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 5
- R1 Radiological Protection and Chemistry Controls . . . . . . . . . . . . . 45 l R2 Status of Radiological Protection and Chemistry Facilities and Eq uip m e nt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 9 R7 Quality Assurance in Radiological Protection and Chemistry Activities
..............................................51 l F2 Status of Fire Protection Facilities and Equipment . . . . . . . . . . . . 52 I F3 Fire Protection Procedures and Documentation . . . . . . . . . . . . . . 53 l
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!. . 1 l F4 Fire Protection Staff Knowledge and Performance . . . . . . . . . . . 54 I l F7 Quality Assurance in Fire Protection Activities . . . . . . . . . . . . . . 55 l
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 6 1 X1 Ex;t Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 l
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EXECUTIVE SUMMARY I Millstone Nuclect Power Station Combined inspection 245/98 212; 336/98-212; 423/98-212 i
Operations e At Unit 1, the licensee had initiatives in progress to define the decommissioning plan and project, evaluate which plant systems and interfaces need to be maintained for the safe storage of fuel, define the set of surveillance and technical specification equipment requirements needed to support a defueled status, and to prepare proposed changes to the license as needed. (Section U1.01.1)
e At Unit 2, the increase in procedure changes requested by operators reflects a higher standard for procedure quality and adherence. This higher standard is l encouraged by management despite the large backlog of procedure changes needed for restart. (Section U2.03.1)
e The licensee performed the Unit 3 startup in a controlled and conservative manner following a shutdown which lasted in excess of two years. Improved operator performance since the NRC operational safety team inspection (OSTI) inspection (IR 50-423/97-83) was noted. Appropriate actions were taken in response to equipment, environmental, performance and procedural problems. Overall, the NRC around-the-clock shift coverage noted good licensee performance consistent with that of a plant returning from an outage over two years in duration. it was also ;
consistent with other NRC operationalinspection coverage of the startup and power j ascension. (Section U3.01.2) i e The corrective actions taken by the licensee for the Containment Manual (Outside Containment) Valve Checklist, which did not contain the complete list of manually operated CIVs that require monthly closure verification are deemed to be adequat LER 423/97-034-00 is considered closed. The failure to perform the required Technical Specification surveillances is a non-cited violation. (Section U3.0 Maintenance o As a result of the blackness testing in the Unit 1 spent fuel pool, a double blade guide unit became lodged on the main fuel hoist grapple. The troubleshooting activities that resulted in dislodging the double blade guide unit from the grapple were well planned and carefully executed. The use of an underwater camera in the spent fuel pool provided an excellent vantage point to monitor the troubleshooting activities. (Section U1.M1.1) l l
e At Unit 1, the licensee successfully retrieved a hatch bolt from the standby liquid .
- control tank. The work was performed under a special procedure with direction l l i l
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from the chemistry department. Proper safety precautions were taken for handling sodium pentaborate. (Section U1.M1.2)
e At Unit 1, the inspector concluded that while the licensee was slow to respond to available indications of emergency diesel generator heat exchanger fouling, the post-identification response was very good. in addition, the licensee's response was characterized by effective maintenance that expeditiously returned the diesel generator to available status. (Section U1.M1.3)
e At Unit 2, the NRC reviewed the corrective actions for eel 50-336/97-02-12, which involved numerous examples of where the surveillance procedures did not satisfy technical specification (TS) requirement. The licensee's review of surveillances required by TS Section 4, including the inservice Test (IST) Program, and the TRM was comprehensive and well documented. This is evidenced by the fact that a total of 57 examples of inadequate surveillances have been reported in LERs since mid-1996. eel 50-336/97-02-12 and Unit 2 Significant items List (SIL) No. 8 remain open pending: (1) completion of the surveillance procedure changes to address the non-conformances that have been reported in LERs (excluding the 15 IST surveillances which are being tracked by Unit 2 SIL No. 49), and (2) verification of the licensee's plans for ensuring that corrected surveillances are performed as necessary prior to declaring systems operable. (Section U2.M8.1)
e The licensee's corrective actions for a Unit 2 radiation monitor annunciator that was incorrectly bypassed during the performance of a surveillance have been completed and are adequate to support closure of LER 97-013-00. The failure to perform the required Technical Specification surveillances is a non-cited violation. LER 50-336/97-013-00 is closed. (Section U2.M8.2)
e At Unit 2, the licensee's corrective actions were acceptable to address Licensee Event Report (LER) 50-336/97-16-00 which described that two surveillance requirements associated with the turbine driven auxiliary feedwater pump (TDAFWP)
were not being implemented prior to entering Mode 3 as required. The NRC found that the instructions and signoffs in the corrected surveillance procedure did not clearly specify that starting the TDAFWP from the control room was a specific technical specification requirement that must be verified. The licensee agreed to enhance the procedure to address this concern. The failure to perform the required Technical Specification surveillances is a non-cited vio!ation. LER 50-336/97-16-00 is closed. (Section U2.M8.3)
e The inspection of selected Unit 3 maintenance activities, including field
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observations, controlling document reviews, and the implementation of work controls, identified acceptable practices and proper coordination between maintenance personnel and the operations department. Where questions were raised regarding tagging and post-maintenance testing coritrols, the licensee provided adequate responses to demonstrate the acceptability of component statu Nuclear Oversight involvement in the inspection and assessment of ongoing
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maintenance activities and in the planning and execution of programmatic audits affecting maintenance work was evident. (Section U3.M1.1)
e The preventive maintenance instructions for the Unit 3 station blackout ( SBO)
uninterruptable power supply (UPS) did not include any acceptance criteria; the j licensee did not follow the written directions of AWO M3 96-18284; and the results l had not been evaluated in a timely manner. This appears to be a weakness in i
translating the requirement for preventive maintenance on the station blackout '
l diesel to an AWO. (Section U3.M1.2)
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- Engineering l e At Unit 1, based on tlie inspector's review of a sample of 10 CFR 50.59 safety evaluations and screenings, the licensee is in compliance with 10 CFR 50.59 for those evaluations reviewed. The safety evaluations were well written and the conclusions reached were adequately supported. In all of the safety evaluations reviewed, the inspector agreed with the licensee's conclusions that the changes were not unreviewed safety questions. (Section U1.E1.1)
l e The Electrical Equipment Qualification (EEO) Program at Unit 2 includes the l technical elements of a good program. The licensee is currently updating all EEO -.-
! related documents and addressing self assessment findings. This is expected to be-
' completed in the fall of 1998. There are relationships and interactions between EEQ i and many other site programs. Unit 2 Significant items List No.19 is considered ;
l updated. (Section U2.E1.2) !
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e At Unit 2, the licensee's corrective actions to address non-conservative technical specification limits for inoperable main steam safety valves were acceptable. Unit 2 Significant items List No. 48 is considered closed. (Section U2.E1.4)
- e At Unit 2, the licensee's corrective actions to address the potential steam generator j overpressure due to restrictive main steam safety valve piping were acceptable.
! Unit 2 Significant items List No. 40 is considered closed. (Section U2.E8.2)
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e The Unit 2 Material Equipment and Parts List (MEPL) Program appears to be J proceeding well at this time. Escalated Enforcement items 50-336/96-201-42 & 43 remain open pending: the completion of necessary MEPL evaluations, the completion of the final operability determination, the completion of the technical l evaluation that justifies the 10 year work history review, and the specification and implementation of necessary corrective actions for instances of non-safety-related parts installed in efety-related components. Unit 2 Significant items List No.18 is considered updsca. (Section U2.E8.3)
[ e At Unit 2, the licensee has completely revised the calculation evaluating the design l adequacy of the modifications to the reactor building closed cooling water (RBCCW)
l surge tank supports. The NRC found that the revised calculation acceptably l
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demonstrates the design adequacy of the modifications to the RBCCW surge tan Unit 2 Significant items List No. 28 is considered closed. (Section U2.E8.5)
i e The licensee's corrective actions for the missed medium voltage breaker overhauls were prudent and timely fnllowing their discovery of the missed overhaul recommendation. The inspector concluded that sufficient justification existed for breaker operability based on the GE letter that stated that no potential problems ,
were found as a result of the completed overhauls performed to date which found l no common mode failure mechanism that would interfere with plant safety. The failure to perform period overhauls on medium voltage breakers is an Unresolved item, because the licensee had not equated overhauls to be part of the inspection and preventive maintenance recommendations. (Section U3.E1.1)
e The actions taken by the licensee to resolve the inability of Power Operated Relief Valves (PORVs) 3RCS*MV8000 A/B to perform their intended function to close and reopen under design basis accident conditions are deemed adequate. New Anchor Darling valves have been tested, and installed. This licensee-identified and corrected l violation is being treated as a non-cited violation. LERs 96-019-00/01 are close (U3.E8.2)
e . The summary table of the Design Basis Differential Pressure Calculation for all four Main Steam Atmospheric Relief Valves (3 MSS *MOV74A/B/C/D) did not include the throttle /close direction safety function stroke which was described in the body of the valve calculation for the referenced valves. The calculations have been revised and the valve settings changed to meet design basis requirements. The actions i taken by the licensee are deemed to be adequate. This licensee-identified and corrected violation is being treated as a non-cited violation. LER 423/96-020-00 is closed. (U3.E8.3)
- An evaluation of all Motor Operated Valves (MOVs) within the scope of Generic Letter (GL) 89-10 was performed by the licensee to determine if the referenced MOVs would have stroked under design basis conditions. This review identified 27 MOVs that potentially may not have stroked fully under design basis conditions. The revisions to the calculations, the valve modifications and the static testing have been completed adequately. This licensee-identified and corrected deficiency is being treated as a non-cited violation. LER 96-035 00 is closed. (U3.E8.4)
Plant Support e Licensee review and assessment of work activities conducted in the Unit 2 reactor cavity on May 23,1998, determined that radiological controls and radiation protection practices were not in compliance with regulatory requirements and licensee management expectations, and that weaknesses existed in the management of the radiation protection organization. While the fin $ngs resulted in the identification of a non-cited violation, with respect to survey performance, em -comprehensive corrective actions were initiated to effect resolution of the licensee-identified issues. (Section R1)
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e The licensee maintained effective radioactive liquid and gaseous effluent control programs in that: (1) effluent control procedures were sufficiently detailed to facilitate performance of all necessary steps: (2) the TS/ODCM requirementr, for reporting effluent releases and projected doses to the public were effectivr,ay implemented; and, (3) the ODCM contained sufficient specification, information, and instruction to acceptably implement and maintain the radioactive liquid and gaseous l effluent control programs. (Section R1.1) '
l e At Unit 3, the licensee established, implemented, and maintained an effective i radiation monitoring system program with respect to electronic and radiological calibrations. As a result of self-assessment initiatives, the licensee implemented efforts to improve radiation monitoring system reliability. Licensee tracking and i l trending efforts provided sufficient information to assess RMS performanc (Section R2.1)
e The licensee established, implemented, and maintained an effective quality assurance program for the radioactive effluent control program with respect to audit l
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scope and depth, audit team experience, and response to audit findings. The l licensee implemented an effective quality control program to validate measurement I results for radiorctive effluent samples. (Section R7)
e At ' Unit 3, all t two of the inspected fire seals were satisfactory with regard to physical damas . shrinkage, and separation. The licensee took appropriate corrective act.< s upon the discovery of the two faulty fire seals. (Section F2.1)
e The licensee conducted a detailed silicone RTV foam fire barrier penetration seal audit at Unit 3 for expired materials and found no evidence of expired material usage. The inspector identified one minor violation, with two exaraples, which resulted from the failure to follow fire barrier seals installation procedures. (Section F3.1)
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Summarv of Plant Status l
Unit 1 remained in an extended maintenance mode for the duration of the inspection i
period. On July 21,1998, the licensee informed the NRC pursuant to 10 CFR 50.82(a)(1)(l) and 50.82(a)(1)(ii) that the fuel had been permanently removed from the Unit l 1 reactor vessel and that the reactor would no longer be operated. The decision to I decommission the facility followed an economic analysis that showed continued recovery l and subsequent operation was not favorable. Unit 1 had been shutdown since November l l 4,1995, when the plant entered the Cycle 15 refueling outage. During the outage all the fuel assemblies were off loaded to the spent fuel pool for temporary storage. The removal of the fuel from the reactor vessel was completed on November 19,199 U1.1 OperallQna U101 Conduct of Operations 01.1 Cessation of Ooerations insoection Scoce (71707)
The purpose of this inspection was to review the licensee activities following the decision to permanently cease plant operation Observations and Findinas On July 21,1998, the licensee submitted a letter to the NRC pursuant to 10 CFR 50.82(a)(1)(l) and 50.82(a)(1)(ii) certifying the permanent cessation of operations as of July 17,1998, and that the fuel had been permanently removed from the reactor vesse Upon docketing of the July 21 certification letter, the licensee was no longer authorized under operating license DPR-21 to operate the reactor, or to place or retain fuel in the reactor vessel. The licensee has two years following permanent cassation of operations to submit the Post Shutdown Decommissioning Activities Report (PSDAR). The licensee intends to use the initial part of this period to analyze and plan the decommissioning options. The PSDAR will describe the planned decommissioning activities, describe a schedule for accomplishing the activities, provide an estimate of the cost of the decommissioning, and discuss the environmental impacts. The PSDAR will be supplemented by the license termination plan, which will identify the activities and schedule for releasing the site for unrestricted use. The licensee cannot begin any major activities to dismantle the plant until 90 days after the submittal of the PSDA The current strategy for the Unit 1 decommissioning consists of three major aspects: 1)
examine the decommissioning options; 2) develop a decommissioning plan; and 3) ensure the Unit 2 recovery is supported. During this interim planning period before decommissioning activities begin, the Unit 1 Director formed a multi disciplined advisory committee to review how the decommissioning of the unit should proceed. The l Predecommissioning Advisory Committee (PDAC) will provide short term action
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is in place. The PDAC is currently reviesving decommissioning requirements, programs and processes, and gathering industry infce, ition on decommissioning. The team has received information from Maine Yankee, Connecticut Yankee, Shoreham, and Dresden facilities, in I addition, the operations department has appointed a shift manager to work with the PDAC l and specifically review the activities in support of the transition to decommissioning from an operations perspective. These reviews include: control room staffing; systems required l to monitor fuel pool cooling and support Units 2 and 3; the modification of technical specifications; procedure reviews; and surveillance testing. To date, the PDAC had determined that the first priority for the unit is to perform an accident analysis reflecting the current state of Unit 1. This new accident analysis will provide a basis for technical l specification changes and any physical changes to the plant performed under the 10 CFR l 50.59 review process, in support of the decommissioning status of the facilit , Conclusions The licensee had initiatives in progress to define the decommissioning plan and project, evaluate which plant systems and interfaces need to be maintained for the safe storage of fuel, define the set of surveillance and technical specification equipment requirements needed to support a defueled status, and to prepare proposed changes to the license as neede U1.Il Maintenance U1 M1 Conduct of Maintenance M 1.1 Spent Fuel Pool Bridae Gracole Insoection Scone (61707)
In June 1998, the licensee performed blackness testing in the Unit 1 spent fuel poo Blackness testing was performed to measure thermal neutron attenuation in the wall of the Unit 1 spent fuel storage racks that utilize Boraflex as the neutron absorber material. As a result of the blackness testing, a double blade guide unit became stuck on the main fuel hoist grapple, and the licensee terminated the testing prior to the completion of desired data collection. On July 9,1998, the inspector observed the troubleshooting activities that resulted in dislodging the double blade guide unit from the main fuel hoist grapple. The inspector reviewed the troubleshooting / testing plan and the associated safety evaluation screening for Observations and Findincis i The troubleshooting / testing plan clearly defined the scope of the work with specific termination points identified. During the pre-job briefing, responsibilities were assigned and contingencies were discussed. A videotape from previous troubleshooting activities was reviewed during the pre-job briefing, which was helpful in understanding the removal plan for the blade guide. During performance of the work, health physics support was excellent (including the control of foreign material exclusion areas). In accordance with the plan, the grapple was given an open signal, visually verified open using an underwater camera, and l
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raised three inches with the blade guide attached. The grapple was mechanically agitated by moving the grapple back and fourth several times, and resulted in the blade guide dislodging from the grapple and settling into the storage rack. Following the dislodging, the grapple was raised slightly and visually inspected and appeared to be undamaged. The troubleshooting plan was completed and the refueling bridge was tagged out-of-servic Good management support and oversight were apparent throughout the activities.
r Conclusions
As a result of the blackness testing in the Unit 1 spent fuel pool, a double blade guide unit became lodged on the main fuel hoist grapple. The troubleshooting activities that resulted in dislodging the double blade guide unit from the grapple were well planned and carefully executed. The use of an underwater camera in the spent fuel pool provided an excellent ;
vantage point to monitor the troubleshooting activitie M1.2 Standbv Licuid Control Tank I Insoection Scooe (627071
.The inspector reviewed the preparation and planning activities associated with the retrieval of a hatch bolt from the standby liquid control (SBLC) tank. While sampling the SBLC tank ;
on June 19,1997, the threaded hatch bolt that holds the tank cover in place unscrewed l and dropped into the tank (CR M1-97-1520). The inspector also observed the removal of I the hatch bolt on July 14,199 Observations and Findinos j The inspector reviewed special procedure (SPROC) 97-1-36, Revision 0, " Retrieval of Foreign Material from SBLC Tank." The procedure provided instructions for the retrieval of items or debris trapped or discovered in the SELC tank. The retrieval work was performed under the direction of an AWO job supervisor from the chemistry department, with j guidance from health physics, maintenance, and engineering representatives. Additionally, a nuclear oversight inspector was present. Site cire Protection emergency medical technicians provided a portable eye wash statien at the job site and tested the atmosphere in the SBLC tank prior to beginning work. An underwater camera was ried to facilitate the retrieval work and to perform tank inspections. Proper safety equipment was used during l the work including: f all protection, face shieids, and chemical resistant gloves for handling sodium pentaborat The hatch bolt was removed from the tank and a visualinspection of the tank internals was ,
performed. The tank was in excellent condition and no deficiencies were noted. in '
addition, the suction strainer was inspectea and found to be intact and free of obstruction ,
4 Conclusien 1 The licensee successfully retrieved a hatch bolt from the standby liquid control tank. The work was performed under a special procedure with direction from the chemistry department. Proper safety precautions were taken for handling sodium pentaborat M1.3 Emeroencv Diesel Generator Heat Exchanaer Foulina Insoection Scone (62707)
The inspector observed licensee response to abnormal lube oil temperatures identified during a previous emergency diesel generator (EDG) surveillance. The response included troubleshooting and subsequent identification of degraded service water flow due to heat exchanger foulin Observations and Findings On August 17,1998, the licc...ae n itiated condition report (CR) M1-98-0589, which documented the identification of an EDG engine lubricating (lube) oil filter outlet
. temperature (182 F) outside the desired value. The abnormal temperature was noted -
during an EDG surveillance run conducted on July 23,1998, wherein the 182*F value was in excess of the desired range of 168 F to 178 F. Subsequently, the licensee performed
, troubleshooting and determined that the condition resulted from a reduced service water 2 (SW) flow of 270 gpm. Prior to implementing a flow balance troubleshooting plan to evaluate the reduced SW flow, the licensee determined that the EDG coolers were possibly fouled based on degraded EDG SW flow, increasing heat exchanger differential pressures, and other trended surveillance data. For example, the surveillance data indicated a decreasing SW flow that ranged from approximately 360 gpm on October 14,1997, to the 270 gpm identified during the July 23, EDG surveillance ru On August 21,1998, the licensee inspected the EDG heat exchangers and identified that multiple tubes were fouled by flaky debris. In addition, the sacrificial zinc anodes were found to be significantly worn or completely eroded away, and was later confirmed by tests to be the source of the flaky debris. As a result, the licensee initiated CR M1-98-0605 documenting the tube fouling, cleaned the heat exchangers which removed the zinc flakes, and replaced all the zinc anodes. The EDG surveillance run that followed produced an increased SW flow rate of 410 gpm, as well as lube oil temperatures that were within the desired band. Corrective actions recommended in CR M1-98-0605, were to (1) ,
hydrolase the EDG heat exchangers due to the scale that was identified on the tubes when ]
they were opened for inspection, and (2) to establish a preventive maintenance (PM) l procedure whereby an appropriate periodicity for cleaning the EDG heat exchangers would be established. The heat exchanger PM will be established to supplement an existing maintenance procedure (MP) that specifically requires inspection of the EDG heat exchangers for scale, debris, and zinc anode condition. However, the maintenance procedure occurs at an augmented frequency based on 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> of accrued EDG operation, and supports the licensee's future establishment of the aforementioned heat exchanger P l
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! Conclusions I i
, .The inspector concluded that while the licensee was slow to respond to available l
indications of ' emergency diesel generator heat exchanger fouling, the post-identification I response was very good. in addition, the licensee's response was characterized by L
effective maintenance that expeditiously returned the diesel generator to available status.
l U1.Ill Enaineerina U1 E1 Conduct of Engineering
.E CFR 50.59 lmolementation l . Insoection Scone (37001)
' The inspector reviewed the licensee's implementation of 10 CFR 50.59 " Changes, Tests and Experiments." This regulation allows licensees to (1) make changes in the facility as-described in the~ safety analysis report, (2) make changes in the procedures as described in'
the safety analysis report, and (3) conduct tests or experiments not described in the safety analysis report, without prior NRC approval, unless the proposed change, test or experiment involves a change in the technical specifications or an unreviewed safety-question. The inspector reviewed the licensee's procedures for implementing 10 CFR l 50.59; reviewed 'a 5% sample of the latest 10 CFR 50.59 safety evaluations (the safety '
evaluation establishes whether or not the change involves an unreviewed safety question)
performed by the licensee; and reviewed a sample of design and procedure changes that i
< the licensee determined did not require a 10 CFR 50.59 safety evaluation because an initial screening determined that the change did not affect the facility as described in the safety ana' lysis repor Observations and Findinos !
'On June 30,1998, the licensee submitted its annual report, covering calendar year 1997, on 10 CFR 50.59 safety evaluations. The inspector selected approximately 5% of the issues presented in the licensee's report and reviewed them to determine if they met the licensee's procedure for conducting 10 CFR 50.59 safety evaluations. In March 1998, the licensee significantly revised its procedure for performing 10 CFR 50.59 safety evaluation The 10 CFR 50.59 safety evaluation procedure that was in effect when most of the safety evaluations were written was Nuclear Group Procedure,3.12. Therefore, the inspector reviewed the 5% sample of.10 CFR 50.59 safety evaluaticns to ensure they were performed in accordance with the procedure in effect when the safety evaluation was performe .The 5% sample reviewed by the inspector included a design change, operability determination, FSAR revision, procedure changes, and Technical Requirements Manual changes. The 10 CFR 50.59 safety evaluations reviewed by the inspector were in
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conformance with the licensee's procedure in effect at the time of the 10 CFR 50.59 safety evaluation. The safety evaluations were well written and the conclusions reached were adequately supported. In all of the safety evaluations reviewed, the inspector agreed with the licensee's conclusions that the changes were not unreviewed safety question In addition to sampling the 10 CFR 50.59 safety evaluations, the inspector also reviewed several 10 CFR 50.59 screenings (these were changes to the facility that the licensee determined did not require 10 CFR 50.59 safety evaluations). The inspector noted that some of the screenings did not reference the FSAR sections that were reviewed to determine whether or not the proposed changes changed the facility as described in the FSAR. The licensee was able to provide information to show that the applicable procedure in effect at the time of the screenings did not require a listing of the FSAR sections reviewed. Current procedures do require a list of the FSAR sections that were referenced to reach the conclusion that the facility as described in the FSAR was not changed. Since the licensee's 10 CFR 50.59 screenings were in accordance with their procedures in effect at the time and those procedures were in conformance with 10 CFR 50.59, the inspector I determined the licensee's 10 CFR 50.59 screenings were acceptable. The inspector noted that the screenings performed later in the year were a higher quality than those performed earlier in the yea Conclusions Based on the inspector's review of a sample of 10 CFR 50.59 safety evaluations and screenings, for the sample selected, the licensee is in compliance with 10 CFR 50.59. The safety evaluations were well written and the conclusions reached were adequately supported. In all of the safety evaluations reviewed, the inspector agreed with the l licensee's conclusions that the changes were not unreviewed safety question .
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Reocrt Details Summarv of Unit 2 Status The unit was initially shut down on February 20,1996, to address containment sump screen concerns and has remained shut down to address the problems outlined in the Restart Assessment Plan and an NRC Demand for Information [10 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 Unit 2 entered the inspection period with the core off-loaded. During the inspection period, I the licensee declared the Facility 1 service water header, the "A" emergency diesel generator, the vital Facility 1 AC and DC electrical distribution systems, the auxiliary exhaust mode of the Facility 1 enclosure building filtration system, the Facility 1 control room air conditioning system, and the Facility 1 engineered safety features actuation i system operable to allow for movement of loads over the spent fuel pool in accordance with technical specification 3.9.1 U2.I Operations U2 01 Conduct of Operations 01.1 General Comments (71707)
Using inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant operations, including observations of operator evolutions in the control room; walkdowns of the main control boards; tours of the Unit 2 radiologically controlled area and other buildings housing safety-related equipment; and observations of several management planning and plant operations review committee (PORC) meeting Specifically, the inspector observed operational preparations, procedural adherence, and the control of shutdown risk during portions of the following evolutions:
e Dual emergency diesel generator outages to support service water system liner inspection and repair e Vital 4160 Volt and 480 Volt switchgear outages for breaker overhauls and fire penetration inspections (including temporary modification 2-98-024, which temporarily replaced QA category 1 vital 480 Volt breakers with functionally equivalent unqualified breakers)
e Transfer of the protected Facility to Facility 1 and declaration of Facility 1 auxiliary exhaust mode of the enclosure building filtration system as operable to allow for movement of loads over the spent fuel pool in accordance with Technical
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Specification 3.9.15
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.Throughout the above evolutions, the inspectors noted good sensitivity to special conditions and equipment outages that affected shutdown safet U2 0 Operations Procedures and Documentation
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03.1 Imorovements in Ooeratina Procedure Qualitv: (Undate - Unit 2 Sienlfl cant items List No.81 insoection Scone (71707)
The inspector evaluated the licensee's efforts to improve the quality of operating procedure Observations and Findinas j-The inspector noted a number of examples where operator performance was good !
regarding the identification of deficient operating procedures. Some deficiencies were 1 identified during the pre-planning process and in other instances operators stopped the '
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performance of the evolution to correct procedure problems. Examples of operating procedure changes include:
o Procedure OP 2304C, " Makeup Portion of the Chemical and Volume Control l System"- Procedure allowed the use of 55 pound bags of boric acid during batching !
evolutions when 50 pound bags are normally delivere ; o Procedure OP 2310, " Shutdown Cooling System" - Added section to provide :
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guidance for the intermittent use of the system with the core off-loaded.
- o Procedure OP 2304E, " Charging Pump Operation" - Procedure did not work well in I
tandum with procedure OP 2304F, " Chemical and Volume Control System Operation During Cold Shutdown."
c, . C.gnclusion The increase in procedure changes requested by operators reflects a higher standard for procedure quality and adherence. This higher standard is encouraged by management despite the large backlog of procedure changes needed for restar U2.ll Maintenance U2 M1 Conduct of Maintenance t M1.1 General Maintenance Observations 4 I Insoection Scone (61726/62707)
- During routine plant inspection tours, the inspectors observed, on a random sampling basis, j maintenance and surveillance activities to evaluate the propriety of the activities and the
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functionality of systems and components with respect to technical specifications and other requirement Observations and Findinas The inspectors reviewed surveillance procedures and maintenance work orders and interviewed licensee field personnel to verify the adequacy of work controls. The inspector observed all or part of activities performed under the following procedures or work orders:
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AWO M2-97-11317 Examine "A" Service Water Pump Discharge Strainer after Failed Retest
- SP 2613-1 "A" Emergency Diesel Generator (EDG) Loss of Load Test
. AWO M2-98-03973 Open and Perform Robotic Inspection of the Refueling Water Storage Tank (RWST)
The inspectors found the inspection and testing performed under these procedures and maintenance work orders was thorough and satisfied the objectives of the activity. The !
loss of load testing demonstrated acceptable performance of the EDGs with respect to '
technical specification requirements, and the inspection of the RWST confirmed that j internal conditions were consistent with design documents and analyse Conclusions The plant staff used the appropriate procedures and completed the work as outlined in the work package U2 M8 Miscellaneous Maintenance issues !
M8.1 (Ocen) eel 50-336/97-02-12 and VIO 50-336/96-08-07: Numerous Examoles of I
Inadeauate Surveillance Procedures: (Undate - Unit 2 Significant items List No. 81 Insoection Scone (92902)
The scope of this inspection was a review of corrective actions taken to address the concerns discussed in Escalated Er.forcement item (EEI) 50-330.37-02-12. In a letter dated April 16,1998, the NRC stated that enforcement discretion was being exercised for eleven Eels, ine,luding eel 50-336/97 02-1 Observations arvifjqdings eel 50-336/97-02-12 concerned the fact that 17 licensee event reports (LERs) involving inadequate surveillance procedures had been issued in the preceding six month period. The
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NRC had previously issued Violation 50-336/96-08-07 which involved an inadequate surveillance procedure for performing containment integrity valve lineups. In their response to Violation 50-336/96-08-07 dated December 27,1996, the licensee committed to review all surveillance procedures for conformance to Technical Specifications (TS). In addition, reviews of surveillance procedures were performed as part of their configuration management program (CMP).
The inspector found that the surveillance review conducted by Technical Support Engineering was thorough and well documented. For each individual surveillance requirement, the implementing surveillance procedures are listed and a description of how the procedure satisfies the TS requirement is provided. Each item was independently reviewed by the responsible engineering supervisor. All 462 TS surveillance test line items
, in TS Section 4 and all 102 tests required by the Technica: Requirements Manual (TRM)
I were included in the review. The TS surveillances were reviewed as to their applicability to each reactor mode (1 - 6).
l The licensee's review identified approximately 480 deficiencies in the TS Section 4 surveillance test procedures and 53 deficiencies in surveillance tests associated with the TRM. Most deficiencies were minor and did not reflect on the adequacy of the test to meet the requirements of the TS or the TRM. However, all or portions of 25 surveillance -
I procedures did not meet the TS requirements and were reported in LERs. This is in addition I
to the 17 examples already identified in eel 50-336/97-02-12. As of the date of this inspection,116 of the 480 deficiencies remain uncorrected. The licensee has developed a tracking system to ensure surveillance tests have been corrected prior to entry into a higher j mode for which the test is required to be performe ,
in addition to the TS review performed by the system engineers, the CMP process also l l-reviewed selected surveillance test prccedures associated with the system being reviewed l to assure conformance with the licensing basis. However, this was not a 100% revie l The results of this review are being evaluated by the NRC's inspection of the CMP effor l l
Between May 2,1997 and July 3,1997, the licensee also performed a complete j assessment of the TS 4.0.5 surveillances which ere associated with the Millstone Unit 2 Inservice Testing (IST) Program. The IST review identified 462 questions or discrepancies in the IST program for which a resolution was required. In addition, an LER was iu,ued for 15 iter s which were considered reportable because certain valves were not included in the I program or were not properly teste Conclusions The NRC reviewed the corrective actions for eel 50-336/97-02-12, which involved numerous examples of where the surveillance procedures did not satisfy TS requirements, and found the license's review of surveillances required by TS Section 4 (including the IST
!. Program) and the TRM was comprehensive and well documented. .This is evidenced by the fact that a total of 57 examples of inadequate surveillances have been reported in LERs i since mid-1996. eel 50-336/97-02-12 and Unit 2 Significant Items List (SIL) No. 8 remain open panding: (1) completion of the surveillance procedure changes to address the non-i i
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conformances that have been reported in LERs (excluding the 15 IST surveillances which are being tracked by Unit 2 SIL No. 49), and (2) verification of the licensee's plans for ensuring that corrected surveillances are performed as necessary prior to declaring systems operable.
T M8.2 (Closed) LER 50-336/97-013-00: Surveillance Procedure Bvoasses Wrona Radiation
Monitor Annunciator Insoection Scone (92700)
The inspector reviewed the licensee's corrective actions associated with Licensee Event Report (LER) 50-336/97-013-00, which involved a radiation monitor annunciator that was
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incorrectly bypassed during the performance of a surveillance. The inspection included interviews, evaluation of licensee response in accordance with 10 CFR 50.73, as well as the review of applicable procedures and other documentation i Observations and Findinos On April 11,1997, the licensee identified that procedure SP2404AL, " Containment Gaseous Process Radiation Monitor RM 8123B Calibration," spec.'fied bypassing the wrong-annunciator. Specifically, the procedure directs placement of an ekctrical jumper for
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monitor RM 8132B, the stack gaseous radiation monitor, rather than thc required containment gaseous radiation monitor, RM 81238. While the installation of the electrica jumper was intended to prevent repeated alarms in the control room during performance of the surveillance, the incorrect placement of the jumper rendered the stack gaseous
- radiation monitor inoperable. Consequently, the licensee was not aware of the inoperable
- stack monitor, and failed to perform required actions in accordance with Technical l Specification (TS) 3.3.3.10. As a result, the licensee determined the event was reportable-pursuant to 10 CFR 50.73(a)(2)(1)(B), as an operation or condition prohibited by the plant's TSs.
.The licensee subsequently performed a root cause evaluation, and as specified in the LER, the cause was determined to be inattention to detail during the procedure validation and
- verification. The inspector also identified that the licensee's corrective actions from the
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LER were implemented, including: (1) As a short term measure, the calibration procedure
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for the containment gaseous radiation monho procedure SP2404AL, was revised such that the correct annunciator was jumpered. As a long term measure, the calibration procedure was revised, such that the applicable annunciator was bypassed using an alarm I'
defeat switch rather than an electrical jumper; and (2) The licensee reviewed remaining radiation monitor calibration and functional test procedures for similar problems and none were identified.
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The inspector verified that the licensee's response to the event was in accordance with the reportability provisions of 10 CFR 50.7 :
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' Conclusions
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The licensee's corrective actions for a radiation monitor annur.ciator that was incorrectly bypassed during the performance of a surveillance have been completed and are adequate to support closure of LER 97-013-00. The failure to perform the required Technical i Specification surveillances is a violation of NRC requirements. However, in accordance with the NRC Enforcement Policy, NUREG 1600, Section Vll.B.1, this is considered to be a i
licensee identified, non-cited violation (336/98 212-01). LER 50-336/97-013-00 is close M8.3 (Closed) LER 50-336/97-16-00: Technical Soecification 4.0.4 incorrectiv Anolied to l Surveillance Reauirements for the Turbine Driven Auxiliarv Feedwater Pumo L
' Insoection Scone (92700)
i j The inspector reviewed the corrective actions taken by the licensee to address Licensee
! Event Report (LER) 50-336/97-16-00, which identified the incorrect performance of
} surveillances for the Turbine Driven Auxiliary Feedwater Pump (TDAFWP) prior to entering
- Mode 3.
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! Observations and Findinas
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j On April 15,1997, during a review of technical specification (TS) issues, the licensee j determined that an exception to the provisions of TS 4.0.4 had been incorrectly applied to
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TS Surveillance Requirements 4.7.1.2.a.1 and 4.7.1.2.a.3. TS 4.7.1.2.a.1 requires that each AFW pump be started from the control room and TS 4.7.1.2.a.3 requires that each l AFW pump be operated for 15 minutes. TS 4.0.4 requires that the surveillances for a
. system be completed prior to entering an operational mode in which that system is required
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'to be operable. Since the AFW system is required to be operable in Modes 1,2 and 3, the 4 surveillance that implements TS 4.7.1.2.a.1 and 4.7.1.2.a.3 is required to be completed p prior to entering Mode 3. TS 4.7.1.2.a.2.b requires a verification that the TDAFWP
- develops a discharge pressure of greater than 1080 psig when the secondary steam supply j pressure is greater than 800 psig. Because a secondary steam supply pressure of greater that 800 psig cannot be attained until the plant enters Mode 3, TS 4.7.1.2.a.2.b states
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that the provisions of TS 4.0.4 are not applicable for entry into Mode 3. However, the y licensee had been incorrectly applying this exception to TS 4.0.4 to TS 4.7.1.2.a.1 and 4.7.1.2.a.3 and therefore, they were not performing the required surveillances prior to
. entry into Mode 3.
3 The safety significance of the error is mitigated by the fact that the surveillance SP 26108,
"TDAFWP Operability and Operational Readiness Tests," which implements TS 4.7.1.2.2.b,
- was being performed prior to entering Mode 3. TS 4.7.1.2.2.b requires the performance of
, a flow test prior to entering Mode 3 to verify the flow path from the condensate storage
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tank to the steam generators. The licensee indicated that although it is not specified in j procedure SP 26108, it is standard practice to start the pump from the control room, and
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that the pump is typically run for 10 to 20 minute .
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The licensee's corrective actions included revising procedure SP 2610B to require starting the TDAFWP from the control room and to verify that the pump is operated for at least 15 minutes. The licensee also reviewed other surveillancus and found no other examples of the improper application of TS 4. The inspector reviewed procedure SP 26108, Revision 11, Change 1, and found that the instructions and signoffs did not clearly specify that starting the TDAFWP from the control room was a specific TS requirement that must be verified. Procedure 2610B, Step 4.2.4, specifies starting the TDAFWP but does not explicitly state that this must be performed from the control room. Step 4.2.4 also does not specify initialing OPS Form 2610B-2 to document completion of the step. In addition, OPS Form 26108-2 incorrectly lists
"TDAFWP Starts from the Control Room" as an " Item" rather than a "TS Acceptance Criteria." The inspector discussed these concerns with the licensee who agreed to enhance the procedure SP 26108 to address these concern Conclusions The licensee's corrective actions were acceptable to address LER 50-336/97-16-00 which described that two surveillance requirements associated with the TDAFWP were not being implemented prior to entering Mode 3 as required. The NRC found that the instructions ~
and signoffs in the corrected surveillance procedure did not clearly specify that starting the TDAFWP from the control room was a specific technical specification requirement that must be verified. The failure to perform the required Technical Gpecification surveillances is a violation of NRC requirements. However, in accordance with the NRC Enforcement Policy, NUREG 1600, Section Vll.B.1, this is considered to be a licensee identified, non-cited violation (336/98 212-02). The licensee agreed to enhance th r,rocedure to address this concern. LER 50-336/97 16-00 is close j2.111 Enaineerina U2 E1 Conduct of Engineering E Recurrina Thermal Overload Alarms for the Containment Sumo Isolation Motor Doerated Valve Actuator Insoection Scooe (37551)
l The inspector reviewed the licensee's selection process for the containment sump motor operated valvo (MOV) actuator thermal overload protection devices to assess the potential for unnecessary operator distraction and accelerated degradation of the actuator, as indicated by recurring alarms. The inspection included review of the licensee's MOV program manual and calculations, and interviews with personnel in the MOV group, Observations and Findinas During static testing of the containment sump isolation valve, 2-CS-16.18, under automated work order (AWO) M2-98-00203 on April 1,1998, the thermal overload l
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protection device for that valve actuator initiated an alarm. The licensee documented the receipt of the alarm in condition report (CR) M2-98-0944. Since that alarm, the thermal ovsrload protection devices associated with MOVs 2-CS-16.1 A and 2-CS-16.1B have initiated additional alarms, which were documented in CR M2-98-2036 and CR M2-98-l 2281, respectively.
l l A thermal overload protection device consists of heating elements arranged in series with
, each phase of the motor windings and thermally sensitive electrical contacts. The heat
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produced by the heating elements increases with the square of the electric current drawn by the motor windings. When the heating elements have raised the temperature to the setpoint of the thermally sensitive contacts, the contacts change state. The thermally sensitive contacts are arranged to control electrical current flow to a relay coil, which positions additional contacts.
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Although these relay coils often are used to open electrical contacts that interrupt power to
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motors, at Millstone Unit 2, the relay coil only actuates an alarm on the main control board.
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This configuration reduces the safety significance of the thermal overload selection because a trip of the thermal overload device would not prevent the completion of the valve's safety function to stroke. However, the inspector questioned the potential for
< unnecessary operator distraction and accelerated degradation of the actuator indicated by -
l the recurring alarms.
l- The licensee's Motor Operated Valve Program Manual provides instructions for thermel overload device selection in PI-6, " Thermal Overload Sizing Evaluation." These instructions list the following acceptance criteria for thermal overloads:
a) The maximum thermal overload trip time is less than the motor's thermal capability at locked rotor current, b) The maximum thermal overload trip time is less than the motor's thermal capability at the motor current corresponding to twice the motor's nominal torque, c) The minimum thermal overload trip time at the current corresponding to twice the motor's nominal torque is greater than the stoke time of the MO d) The minimum thermal overload trip time at the motor's nominal current is greater than the duty cycle time of the MO Section 3.7 of Pi-6 specified that thermal overload devices that do not directly affect valve operation, such as all MOV thermal overload devices at Unit 2, shall be sized at nominal l voltage rather than the maximum expected voltage to prevent motor degradation due to thermal agin The MOV actuators for valves 2-CS 16.1 A and 2-CS-16.1B were rated at a nominal
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voltage of 460 Volts and a maximum voltage of 506 Volts. The licensee conducted
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dynamometer testing of these actuators under AWO M2-97-07967, which provided data including motor speed and current draw versus torque. The licensee determined from this data that the performance of the motors did not correspond to the vendor generic motor ( curve listed on the data sheets for the motors. To addre.ss this discrepancy, the licensee l selected the generic motor curve that best matched the dynamometer test data and other i
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parameters listed on the motor's nameplate from the population of generic motor curves provided by the vendor, l
Using data from the generic motor curve adjusted to match dynamometer test results, the l licensee compared the performance of several thermal overload devices with the acceptance criteria specified in PI-6. These comparisons were documented in calculation change notices 8 and 13 *o calculation 97-ENG-01840E2, Rev.1. Although no thermal overload device satisfied all acceptance criteria, the installed thermal overload satisfied all criteria except the criteria for maximum trip time at locked rotor curren*. The inspector found that this condition was not relevant to the thermal overload trips that had occurred and that the MOV program manual recognized that available thermal overloads may not satisfy all acceptance criteria. The inspector also investigated the potential for actual thermal capability of the motor at nominal torque to differ significantly from the thermal capability projected from the generic motor curve data, but the inspector found that the thermal overload trip time was sufficiently conservative to accommodate a significant difference in thermal capability without causing any undetected thermal degradation of the moto The licensee attributed the thermal overload trip alarms to bus voltage near the maximu design value. Dynamometer testing confirmed that the motors draw about 33 percent greater current at the maximum design voltage than at nominal voltage under the same nominalload. This 33 percent increase in current causes the thermal overload trip time to decrease by about 44 percent. Because bus voltage is expected to return c!oser to nominal
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values when the plant is operating at power and because the experienced thermal overload j trips occurred near the end of the second valve stroke, thermal overload trip alarms from l operation of these valves are not expected when the plant is operating at powe Conclusions The inspector concluded that the licensee's selection process for the containment sump MOV actuator thermal overload protection devices was consistent with their MOV program manual. The setpoint of the tharmal overload devices was sufficiently conservative to !
preclude any undetected thermal degradation of the motors. Also, the reduction in bus voltage when the plant is operating at power is expected to eliminate thermal overload trip alarms from operation of these valves and the associated operator distractio E1.2 Electrical Eauioment Qualification Prooram (Undate - Unit 2 Sianificant items List No.19) Insoection Scooe (37551)
The inspector reviewed the overall status of the Unit 2 Electrical Equipment Qualification (EEO) Program including the licensing basis, internal self-assessments, program documentation, relationship to other site programs, EEQ-related databases, and trainin . - . _ _ _ _ . ._ ._ _ _ _ . _ . . .__ _ _ __ _ _ . _ __ . ._ _..
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16 Observations and Findinas l
l Unit 2 was designed and constructed in accordance with the July 1967, version of the
- General Design Criteria (GDCs) that was proposed by the Atomic Energy Commissio However, the final version of these ODCs was provided in the 10 CFR 50, Appendix A, i Position Paper in February 1971 and vas the standard for the review of the Unit 2 desig '
Requirements pertaining to the environmental qualification of safety-related electrical equipment are embodied in 10 CFR 50.49, " Environmental Qualification of Electric
! Equipment important to Safety for Nucl3ar Power Plants," which was established on January 21,198 For Unit 2 equipment installed prior to February 22,1983, the applicable standards for EEQ are either: the NRC DOR Guidelines at IEEE Standard 3231974, "lEEE Standard for Qualifying Class IE Equipment for Nuclear Power Generating Stations," as implemented by Revision 1 to Regulatory Guide (RG) 1.89, " Environmental Qualification of Electrical l Equipment for Nuclear Power Plants." Equipment installed after February 22,1983, must l meet IEEE 3231974, as implemented by RG 1.89, Rev.1. The major differences between the DOR Guidelines and IEEE 3231974 requirements are preaging, margins, and qualified life determination, of EQ items. Unit 2 contains both DOR and IEEE 323-1974 qualified
. equipment in service. The Unit 2 Final Safety Analysis Report (FSAR) contains EEQ-related topics in a number of FSAR sections, rather than being consolidated in one section as is typical. In addition, there are numerous programmatic and individual component-related licensing commitments relevant to the EEQ program at Unit 2.
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Key EEQ Program documents on site are: the EEQ Program Manual, Specification SP-EE-332 and Specification SP-EE-352. The former specification defines the environment based on the high energy line break (HELB) assessments for various zones, while the latter specification contains the enviranmental qualification information for individual components. Updates to the EEQ Program Manual have been completed, but work is still ongoing by the licensee to update both of the specification On November 7,1996, the licensee issued Engineering Self-Assessment Report (ESAR-PRGM-96-002), which was a comprehensive assessment of the EEQ program, that identified many areas in need of improvement. The licensee has been working stead;ly to address these findings, and not all are fully addressed to dat The licensee's current efforts are focused on evaluating and restoring plant equipment to meet EEQ requirements. However, the inspector noted that there are relationships and interactions between EEQ and many other site programs, such as the Integrated Preventive Maintenance Program (IPMP), the NRC RG 1.97 Instrumentation program, the Material Equipment and Parts List (MEPL) Program, the Seismic Qualification program, and the High Energy Line Break Program. The responsibilities for these other programs reside in many different departments, it is incumbent on licensee management to ensure all of these interfaces are adequately controlled, i
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l j 17 l Conclusions t
After reviewing the various EEQ program documents, the inspector concluded that the program at Unit 2 includes the technical elements of a good program. The licensee is l currently updating all EEQ-related documents and addressing self-assessment findings.
i This is expected to be completed in the fall of 1998. The inspector noted that there are complex relationships and interactions between EEQ and many other site programs. Unit 2 Significant items List No.19 is considered update E1.3 Hiah Enerav Line Break Proaram Evaluation: (Undate - Unit 2 Sionificant items List j No.19)
I Insoection Scoce (37551)
The inspector reviewed the overall status of the Unit 2 High Energy Line Break (HELB)
Program, including the licensing basis, internal self assessments, program documentation, relationships to other site programs, HELB-related databases, and training, Observations and Findinas Safety-related equipment must be designed for the consequences of a High Energy Line Break (HELB) conditions as required by the Appendix A to 10CFR50, General Design Criteria 4 (GDC-4), " Environmental and Missile Design Bases." A high-energy fluid system -
sis defined as those where either the maximum operating temperature exceeds 200 degrees Fahrenheit or the maximum operating pressure exceeds 275 psig. Moderate energy systems are those where operating temperature and pressure are both equal to or less than the above limit Unit 2 contains HELB-related topics in a number of Final Safety Analysis Report (FSAR)
sections. It ws.a also addressed in several FSAR amendments over the years. Other important documents for Unit 2 HELB are NRC Generic Letter 87-11 " Relaxation in Arbitrary Intermediate Pipe Rupture Requirements", Combustion Engineering Topical Report CEN-367-A, the HELB Program Manual, Specification SP-M2-ME-OOO3, Rev. O (12/19/95)
and HELBASIS 130M2, Rev 1 (5/24/97).
During an inspection in 1990, the NRC noted that several HELB issues for the turbine building were unanswered. In November,1993, the licensee was unable to determine if the piping in the condensate storage tank pipe trench had been included in the original HELB design review. These findings led to a complete review of the HELB program for Unit 2. In Septemoer of 1994, a phased approach to the resolution of the HELB issues associated with Outside Containment was initiated. Phases 1 through 3 have been completed. Phases 4 through 6 are underway and making good progres . The licensae's staff has defined all areas outside the containment that ace subject to HELB l consideration. The evaluation process has identified a few systems with about 500 HELB l interactions that were originally unacceptable in accordance to the specifications. They are
- expected to complete this part of the review by the end of August 1998. The pertinent
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, environmental data for each HELB zone has been defined and properly documented for ( evaluating the environmental qualification of equipment.
l The HELB assessment for /nside Containment has been initiated and is scheduled to be
- completed ir September 1998. As part of this assessment, the licensee is addressing the
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concerns described in NRC Information Notice 89-55 " Degradation of Containment isolation
! Capability by a High Energy Line Break." Conclusions The inspector noted that the HELB program at Unit 2 includes all technical elements of a good program. Program upgrades are underway and are expected to be completed soo Unit 2 Significant items List No.19 is considered updated, t
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E1.4 Technical Soecification Limits for Inocerable Main Steam Safetv Valves Are Non-Conservative: (Closed - Unit 2 Slanificant items List No. 48)
l Insoection Scone (37551)
The licensee wrote Adverse Condition Reports (ACRs) M2-96-0542 & M2-06-0667 to
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document the use of non-conservative bases in Technical Specification (TS) Bases B 3/4 7.1, and to correct the affected TS 3.7.1.1. The inspector reviewed the licensee's actions
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to correct the deficiencies documented in the subject ACR Observations and Findings in a review of the TSs, a licensee engineer determined that the values for the reactor trip setpoint listed in TS Table 3.7-1 for 1,2 or 3 inoperable main steam safety valves (MSSVs), were incorrect and non-conservative. Specifically, the tabulated values were not consistent with the equation presented in TS Bases B 3/4 7.1. This deficiency was
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documented in ACR M2 96-054 During the investigstion of ACR M2-96-0542, it was discovered that the wrong event was used as the bases for the TS. This was a result of TS Amendment 52, in which the limiting event for secondary side pressure was chariged from a turbine trip to the closure of a main steam isolation valve (MSIV). This deficiency was documented in ACR M2-96-0667. Owing to the commonality of the deficiencies, ACR M2-96-0542 was closed to ACR M2-96-066 la developing a corrective action plan to address the deficiencies documented in the subject ACRs, the licensee noted that the issue of the controlling event for MSSV actuation was being addressed to resolve the deficiencies identified in Licensee Event Report (LER) 50-336/96-031. This LER discussed the potential to overpressurize the steam generators due
,. to restrictive piping to the MSSVs. Accordingly, the first corrective action for the subject
- ACRs was identical to the commitment made to resolve the LER, namc!y, to complete the
! MSSV analysis with inlet piping modifications. The remaining corrective actions were: to perform an analysis to verify the reactor trip setpoints with inoperable MSSVs with the i
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modified inlet piping; and to submit a TS change request reflecting the possible and desired modes of operatio Rather than perform an analysis to establish the revised reactor trip setpoints with inoperable MSSVs, the licensee decided on a more conservative approach and submitted a TS Change Request to revise TS 3.7.1.1 to remove the ability to operate in Modes 1 or 2 l with inoperable MSSVs. Operation in Mode 3 was retained provided no more than 3 MSSVs are inoperable per SG. This request was accepted by the NRC with TS
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l Amendment No. 21 l l
The inspector reviewed Section 14.2 of the Final Safety Analysis Report (FSAR) to see if i l the single MSIV closure event was identified as the bounding event for the secondary side I
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l pressure. In this regard the FSAR was not clear. The inspector requested clarification of
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this topic from the licensee. The licensee later advised that the inspector's observation was correct and ; hat revisions would be made to the FSAR to clarify this point.
! Conclusions l
l .Through internal review and attention to detail the licensee discovered specific deficiencies
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- in its TSs regarding operations with inoperablo MSSVs. The licensee's corrective actions-
!- to address ACR M2-96-0542 and ACR M2-96-0667, which included a TS change, were found to be acceptable. Unit 2 Significant items List No. 48 is considered closed.
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U2 E8 Miscellaneous Engineering issues E (Closed) Deviation 50-336/94-201-06: Failure to Provide Class IE Power for the Pressurizer Level Post Accident Indication Looos Insoection Scone (92903)
NRC Inspection Report 50-336/94-201, dated December 15,1994, documented the licensee's finding that the pressurizer level instruments did not conform to the power ' !
supply and quality classification attributes described in the licensee's March 2,1992, submittal to the NRC for post accident monitoring instrumentation. The inspector reviewed the following: Final Safety Analysis Report (FSAR) Section 7.5.1.4, " Post Accident Monitoring"; Regulatory Guide 1.97, " Instrumentation for Light-Water-Cooled Nuclear l Power Plants to Assess Plant and Environs Conditions During and Following an Accident";
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the licensee's response to the Notice of Deviation issued with the NRC Inspection Report 50-336/94-201; the applicable sections of the FSAR and Technical Specifications and l - supporting documentation to assess their corrective actions. This included a review of the 1- associated design change request (DCR) and design change notices (DCNs).
l l Observations and Findinas
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! The inspector confirmed that the pressurizer level loops LT-110-X and LT-110-Y were
{ mcved to the Foxboro model Spec 200 instrumentation cabinets RC31C (Front) and RC31D
. (Front). The inspector confirmed that these control room cabinets were powered from the
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i redundant Class 1E,120 Volt ac Vital Instrument buses VA10 and VA20 respectively and l that the calculated loading on these buses enveloped the additional load of these loop .
The inspector interviewed the electrical engineer and designer regarding DCN No. DM2-S-0273-95, which made these changes, and walked down the control room cabinets to confirm that the external cables were color cod sd consistent with that required by FSAR '
Table 8.7-4, " Facility identification." Conclusions The inspector confirmed that the licensee had completed the corrective actions required to categorize the post accident monitoring pressurizer level loops as Category I instrumentation consistent with tha licensee's Regulatory Guide 1.97, Revision 2 commitments. Deviation 50-336/94-201-06 is close '
E8.2 (Closed) LER 503 26/96-031-00/01: Potential Steam Generator Overoressure Due to Restrictive Win dteam Safety Pioina: (Closed - Unit 2 Sianificant items List No. 401 Insoection Scooe (92700)
The inspector reviewed the licensee findings and corrective actions to resolve the condition reported in Licensee Event Report (LER) 50-336/96-031-0 Observations and Findinas LER 50-336/96-031-00 described that during a review of the analysis for the single main steam isolation valve (MSIV) closure event, it was discovered that non-conservative assumptions were made in the modeling of the main steam line, main steam safety valves (MSSVs) and steam generators (SG). The licensee found that the piping pressure losses between the steam generators and MSSVs were not accounted for and as a result, the 110 percent design rating of the steam generators would be exceeded for a single MSIV closure event or a loss of electricaliaad (LOEL) even !
The LER states that the cause of the event was an inadequate design of the MSSV inlet piping and the failure to adequately assess the piping pressure losses to the MSSV. With this LER, the licensee committed to perform the reanalysis and plant modifications necessary to ensure that the plant response to analyzed events will not result in exceeding the design requirements of the steam generators. in conjunction with the LER, the licensee issued Adverse Condition Report (ACR) M2-96-0437 to develop and track the implementation of a corrective action plan to address the issue and satisfy the LER commitments, The corrective actions included: performance of an analysis to determine the expected peak SG pressure during the MSIV closure event; replacement of the MSSV inlet piping with larger inside diameter piping; and investigation of the need for a SG delta-P reactor tri The inspector reviewed the licensee's corrective actions. To support the original finding, l the licensee performed detailed calculations of pressure loss for the MSSV closure event.
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The calculation T-01729-S2, dated June 23,1997, confirmed that the pressure loss to be expected with the original MSSV inlet piping was large. The calculation also investigated various other pipe sizes for the inlet piping and specified a suitable alternate. The inspector considers the calculation to be comprehensive and to provide an adequate basis for the inlet piping size modification.
l To corroborate its findings, and the proposed modifications of the inlet piping, the licensee l solicited the services of Seimens Power Corporation to analyze the MSIV closure event and I
! the loss of electrical load (LOEL) event. The calculation, EMF 97-054, dated July 1997, l was reviewed and found acceptable by a licensee engineer (Memorandum NE-97-SAB-160).
- The analysis results for the closure of a single MSIV with the modified inlet piping, i demonstrated that the maximum SG secondary side pressure was 1092 psia, a value l within the acceptance limit of 1100 psia. The comparable analysis results for the I l' maximum SG secondary side pressure, for the LOEL event, was 1086 psia. These results
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corroborated the adequacy of the proposed inlet piping modification and the fact that the single MSIV closure event is bounding. The analysis further showed that the SG delta- P reactor trip was not necessary.
l With the corroboration of design adequacy, the licensee implemented the replacement of the MSSV inlet piping, Conclusions The licensee has taken appropriate actions to correct the inadequate design of the MSSV
, inlet piping. With detailed calculations, the licensee first substantiated the finding that the l
MSSV inlet piping was under-sized and next corroborated the adequacy of the proposed design modification. The design modifications were then implemented. LER 50-336/96 031-00/01 is close E8.3 (Uodate) Eels 50-336/96-201-42 & 43 and (Closed) IFl 50-336/98 201-16: Materia Eauioment and Parts List Prooram: (Undate - Unit 2 Sianificant items List No.18)
!
l poection Scone
- Unit 2 Material, Equipment, and Parts List (MEPL) Program, Significant items List No.18,
! has been previously reviewed and most recently updated in NRC inspection Report 30-336/98 207. The licensee has not provided any additional updated SIL packages for NRC review. However, this section provides an overview and some update en the specific aspects of the MEPL Program for Unit Observations and Findinas Several previous reports, including the cover letter for NRC Inspection Report 50 336/97-208, highlighted the concern that the licensee had not yet fully developed broader
- corrective actions to address past instances where non-safety-related (NSR) parts were l inappropriately installed in safety-related (SR) components (e.g., for parts that were
- classified as " Undetermined" or "Non-Safety-Related" and had no MEPL evaluations). NRC i
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Inspection Report 50-336/98-201 discussed the same issue and Inspector Followup Item 50-336/98-201-16 was opened due to concerns regarding the sampling approach the licensee was using to address the problem. During the exit meeting for NRC Inspection
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- Report 50-336/97-208 held on May 1,1998, the NRC requested and the licensee I
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committed to provide a written, approved program to the NRC that provides their plans for dispositioning this MEPL concern. On May 14,1998, the licensee submitted letter B17234 l
to the NRC. This letter presented the licensee's plan regarding ongoing activities
! associated with the MEPL program at Unit In the letter the licensee committed that four actions would be completed prior to startup of Unit 2, summarized as follows:
l . Complete component level MEPL evaluations for each component in the Production l Maintenance Management System (PMMS) database, i Populate the PMMS database with MEPL numbers, nuclear indicators, and program l indicator . Perform a work history review of QA category 1 component . Ensure adequate MEPL-related programs for long term operation of Unit The inspector met with licensee personnel and discussed the details of the MEPL program L plans. Particular questions and licensee responses ware as follow Relative to item No.1 above, the licensee stated that all Category 1 and augmented quality components had been added to PMMS. Piping and structural type items are contained in the hard copy MEPL, which is separate from PMMS. Also, the licensee noted that if ongoing maintenance were to identify a component that was not in l PMMS that it would be promptly adde Regarding the parts within components, the licensee stated that not all parts would receive a part-specific MEPL identification, but where no Part-level MEPL i identification was performed, that part would assume the quality category of the l parent component.
l The licensee clarified that a work history review would be performed for all QA l category 1 components to ensure the adequacy of installed replacement parts.
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Further, the criteria for acceptability of this review would be similar to the criteria used in the recently completed Unit 3 work history reviews, r
l The earlier Non Conformance Reports written for upgrades of nonsafety related (NSR) parts would be re-reviewed to the current criteria to ensure proper resolutio . The history at Unit 2 of replacing non-ASME code parts in safety-related ASME
! components with NSR parts is similar to that for Unit 3. Thus, this area would
. receive attention during the work history reviews.
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The ongoing programs for ensuring adequata parts replacement are currently being evaluated and upgrades such as the 3CONFIG Group used at Unit 3 have not been implemented.
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During the last inspection period, the licensee began the work history review process to determine where NSR parts had been installed in SR components. They initially identified
- all components that were within the scope of the review to include: all Category 1 components, all 'U' components, and all 'N' components without a corresponding MEPL
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, identification. The selected period for the review was the 10 year period from January 1988 through June 1998. The licensee stated that this time period would be justified in the Technical Evaluation that is still to be prepared. There were about 47,000 automated
work orders (AWOs) during this period that were screened and reviewed, at various levels of detail. This review resulted in a finding that 387 AWOs, affecting 271 components installed NSR parts in SR components. There were a total of between 400 and 500 parts involved. The licensee documented these findings on CR M2-98-2289, and prepared an initial operability determination (OD MP2-021-98) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as required that provided i a basis for the initial reasonable expectation of continued operability. The final operability determinations were still in progress.
' Conclusions l
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The licensee's MEPL program appears to be proceeding well at this time. Eels 50-336/96-201-42 & 43 remain open pending: the completion of necessary MEPL evaluations, the
completion of the final operability determinations, the completion of the Technical Evaluation that justifies the 10 year work history review, and the specification and
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implementation of necessary corrective actions for instances of NSR parts installed in SR
- components. Inspector Followup item 50-336/98-201-16 was satisfactorily addressed by l the licensee's May 14,1990, submittal and is considered closed.
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E8.4 (Closed) eel 336/96 201-11 and EEi 336/96-201-31: Inadeauate Desian Control Measures Anolied to Modifications to the RBCCW Surae Tank: (Closed - Unh_2 Significant items List NoJS) l Insnection Scone The inspector reviewed the final revisions to Calculation 95-ENG-1198 M2 used to validate the design adequacy of the modifications of the support system for the reactor building
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closed cool 69 water (RBCCW) system surge tank.
1 Observations and Findinas
. NRC Inspection Report 336/96-201 discusses concerrs with a modification of the RBCCW surge tank. The modification had been processed and installed in accordance with Bypass
Jumper (8/J) 2-95-045 and was necessary to resolve tank operability concerns regarding
- the seismic design adequacy of the tank, inspectors noted deficiencies in the installation,
! lack of conformance with the design document (B/J 2-95-045), fai!ure to review / document modifications made at installation, and the inadequacy of calculation 95-ENG-1198 M2,
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Revision 2, to validate the design. The failure to establish controls to ensure that a I temporary modification was installed in cccordance with the approved design document and that subsequent changes were subject to quality design control measures, was considered a violation of 10CFR50, Appendix B, Criterion ill, " Design Control" (eel 336/96-201-11). The failure to verify the adequacy of the design was considered a violation of i 10CFR50, Appendix B, Criterion Ill, " Design Control"(eel 336/96-201-31).
l
Adverse condition report (ACR) M2-96-0465 was issued to document the design control f ailures identified in eel 336/96-201-11 and eel 336/96-201-31. The licensee included the subject eel's in the " Common Cause Assessment of Apparent Violations," dated December 13,1996, that it prepared in response to the many apparent violations identified by the NRC. The licensee also issued ACR 7965 to track and trend an errcr in the design calculation, and ACR's 10214 and 10651 to address deficiencies identified by the inspection team associated with the temporary installation.
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The causes cited for the design control deficiencies were inadequate communication of i management expectations, inadequate work oversight and control, and inadequate engineering design and configuration control. Corrective actions to address the surge tank specific issues and to improve the design control process for both temporary and final modifications were undertaken. Regarding the tank specific issues, calculation 95-ENG-1198 M2 was revised to address the deficiencies noted and the associated final 1 modifications were installe The inspector reviewed the corrective actions taken to address the design control process and concluded they were positive and should improve that process (Inspection Report 50-336/97-203). The inspector determined that the issues raised by the inspection team, regarding Revision 2 of Calculation 95 ENG-1198 M2, had been addressed and/or resolved in Revision 3 to the calculation. However, the inspector noted other deficiencies in the calculation and concluded that the calculation still did not verify the design adequacy of the modified surge tank support system. Essentially th3 assumption of equalload sharing botween the upper and lower wire rope supports was not substantiated and was considered wrong. Concurrently, the licensee had come to the same conclusion and, following discussions with the inspector, issued CR M2-97-1803 to document the concerns regarding the design adequacy of the RBCCW surge tank restraints (Inspection Report 50-336/97-203).
An inspection of the RBCCW tank and the adjacent tornado missile shield was performe Tae permanent modification of the surge tank seismic restraint system was seen to be
, installed and were consistent with the design calculation package. No deficiencies in the installation were note The inspector reviewed Revision 4 to calculation 95-ENG 1198-M2. In this revision, the licensee used a composite model of the RBCCW tank and the tornado missile shield structure to evaluate the modified support system, in all earlier revisions, the tank and shield structures were evaluated separately with the interconnecting cables treated as supports. The inspector considers the composite model to be comprehensive and to more correctly simulate the actual system. An unusual aspect of the system, owing to
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differences in length and geometry of each interconnecting cable, is that it has nonlinear stiffness characteristic Discussions were held with the responsible licensee engineer to resolve questions that the inspector had regarding the calculation. Although the majority of these questions were resolved, three issues required further consideration by the licensee. Specifically, the licensee was requested to provide the following information: validation of its use of linear analysis methods to evaluate the nonlinear system, a basis to support limiting the evaluation to a consideration of the tank being only 67% full (a full tank was considered in the earlier revisions to the calculation), and verification that the inclusion of spectra for the 84 ft. elevation would not change the key evaluation result The licensee provided additional calculations to address the first and third issues, as
)'
follows. To validate the use of the linear analysis method, the licensee performed three time history evaluations (THE) of a simplified model of the system. In the first THE , the supports were assigned the lower bound linear stiffness. In the second THE, the supports were assigned the upper bound linear stiffness in the last THE, the supports were assigned a bilinear stiffness characteristic consistent with the upper and lower bound values. This last THE was a nonlinear system, similar to the tank system, since its stiffness changed as it passed through the neutral point. The time history forcing function-was derived from the response spectra for east / west excitation of the tank. The time history solution mode was used as it is the only mode that can be used for the nonlinear system. The linear analysis results for the first two cases were shown to bound the nonlinear response results developed with the third. The inspector concluded from this that the linear response results developed by the licensee for the tank system should provide conservative estimates of actual system response and was therefore acceptabl To verify that the inclusion of the spectra for the 84 ft. elevation would not impact the key analysis results, the licensee developed and compared spectra for both the 71.5 ft, and 84 )
ft, elevations. In the east / west direction the 84 ft, spectra exhibited a new peak at 4 Hz but was otherwise enveloped by the 71.5 ft spectra. In the north / south direction the 84 ft, spectra enveloped the 71.5 ft. spectra at all frequencies and exceeded it by 10% at the fundamental frequency of the tank. Excitation in the east / west direction governs the design, by a wide margin, and consequentially the spectra comparison results for this direction are of prime importance. The inspector reviewed the spectra results for the E/W direction in conjunction with the natural frequencies for the tank system. At all dominant natural frequencies of the tank system (9.7 Hz and greater) the 71.5 ft, spectra envelopes j the 84 ft spectra and therefore governs design. The new peak at 4 Hz, for the 84 f ;
spectra, is of no consequence, since this frequency is well below the dominant system {
fundamental mode. The greater amplitude of the 84 ft, spectra in the N/S direction is also of no consequence since excitation in this direction does not impact the design. The inspector concluded that the information provided substantiated the licensee's calculational approac The inspector participated, with a member of the NRC Unit 2 ICAVP Out Of Scope System j Inspection review team, in a meeting with the licensee, to discuss inspection Request M2- '
97-NRI-A0205, the surge tank fill issue. Various single failure events, which could lead to
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overfilling the surge tank, were postulated and discussed. For each of these events, which could occur during an SSE event, the surge tank would fill at a rate corresponding to a ( surge tank level rise of less than 14 inches. This is less than the level increase of 24 inches used in the surge tank seismic analysis. The inspector concluded that the licensee's estimate of surge tank overfill, based on thermal volume expansion of the contained fluid, is conservative and acceptably founded on known system parameters and instrumentation.
I The inspector reviewed CR M2-97-1803. The CR documented the deficiency of Revision 3 of Calculation 95 ENG-1198-M2,and specified as corrective actions the complete revision of the calculation and implementation of modifications as required. Revision 4 to the j calculation was completed, and based on the inspectors review, it considered acceptable, j Based on the calculation, modifications of the anchorages of the missile shield to the l Auxiliary Building Roof are required. The modifications consist of adding additional anchor l bolts and necessary load spreading steel plates to the anchorage points. The modifications l
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are being performed under DCN DM2-OO-1454-97 with required completion before entry into Mode Conclusions The licensee has completely revised the calculation evaluating the design adequacy of the-modifications to the reactor building closed cooling water (RBCCW) surge tank support The NRC found that the revised calculation acceptably demonstrates the design adequacy of the modifications to the RBCCW surge tank. eel 336/96 201-11, eel 336/96-201-31, and Unit 2 Significant items List No.28 are considered closed.
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Report Details Summarv of Unit 3 Status Unit 3 began the inspection period in hot standby (Mode 3), awaiting NRC Executive Director of Operations (EDO) approval to restart. This approval was granted on June 29 and operators commenced the startup (Mode 2) at 11:03 on June 30. The reactor was taken critical at 12:45 that day. However, following identification of indication problems with one of the two intermediate range monitors, the licensee returned the unit to Mode 3 later that day to investigate.
l Following repair to the instrument cabling, the reactor was returned to Mode 2 at 11:36 l and taken critical at 13:15 on July 1. Power operation (Mode 1) was achieved at 20:21 on
- July 2. Operators raised reactor power deliberately, per the startup plan, stopping at l
specified power levels for plant management and Nuclear Oversight review and approval to i continue to raise power. The licensee also discussed plant status, technical issues identified, and Nuclear Oversight assessments with the NRC at 30, 50, 75, and 90 percent power hold points to obtain NRC concurrence to continue with the power escalation. The plant reached 100 percent power on July 14,1998, at 21:59, where it remained until -
August 12.
l On August 12 operators commenced a reactor shutdown to repair a leaking valve in the
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auxiliary feedwater system. Following the successful repair to the leaking valve and two other susceptible valves in the system, operators commenced a reactor heatup on August 17, the last day of this inspection period. Mode 4 was achieved at 15:20 that da After the conclusion of this inspection, the licensee presented to the NRC at a meeting open to public observation at Millstone Station on August 18, the results of its plant performance assessment in achieving and maintaining the 100 percent power plateau. As discussed in the following report sections, NRC inspectors closely monitored the power ascension process up to and including the achievement of full power and during the subsequent reactor shutdown activities. In accordance with the NRC letter, dated June 16,1998, acknowledging submittal of the power ascension program for Unit 3, the findings and results of the NRC inspection and assessment of the licensee's completion of its power ascension process are documented in this inspection repor With this change in Unit 3 status, Nuclear Oversight management implemented a major program change, effective July 1, in transitioning from the use of " restart" criteria to more of a functional approach (e.g., operations, maintenance, engineering, etc.) in assessing station performance and the progress of key issues. With the consolidation of items,21 issues under the Nuclear Oversight Restart Verification Plan were reduced to six unit specific issues and five common site issues under the now effective Nuclear Oversight Verification Pla On July 7, the exit findings for an ledependent Corrective Action Verification Program (ICAVP) follow-up inspection of licensee corrective actions were presented at a meeting
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open to public observation at Millstone Station. This inspection, documented in inspection report 50-423/98-211, is the last in a series of tiered ICAVP inspections that commenced at Unit 3 in 1997. The NRC has determined and has notified the licensee that the Unit 3 ICAVP has been completed to the satisfaction of the NRC, as required by Section IV.1 of the August 14,1996, Confirmatory Order for Millstone Station.
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U3.1 Onorations U3 01 Conduct of Operations l 01.1 Ooerational Activities and Control Room Observations
! ; Insoection Scone 161726. 71707)
The inspector conducted frequent tours of the control room, examining the status of plant equipment, reviewing logs and temporary modifications, witnessing operational evolutions, .
[- ' and discussing with the licensed operators and shift managers the governing technical specifications and required entries into limiting conditions for operation. As appropriate, plant inspection-tours were conducted to verify field equipment status consistent with th : operational controls and to check the affected component taggin + Observations and Findinas l- -
- During this inspection period, the inspector specifically witnessed and assessed operational ,
evolutions, to include reactor startups, reactor coolant system dilutions, condenser thermal I backwash controls, and reactor chemistry monitoring and changes. The inspector also reviewed operator response to an erratic intermediate range monitor (IRM) during reactor j startup and to a failed controlling steam generator pressure channel at full reactor powe The use of time domain reflectometry equipment in the nuclear instrument cabinets in the control room was observed to identify a loose cable connection in the containment l
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penetration for IRM 30; and the activities in the auxiliary building to repair this loose connection were checked for proper work controls. Operator response to take manual -
feedwater control to prevent the failed steam generator pressure channel from causing a major level transient was deemed both timely and prope The inspector noted that operations personnel have been very deliberate in procedural review and compliance since commencing routine operations after the two-year Unit 3 outage. The inspector witnessed a questioning attitude by a licensed control board operator during a routine reactor coolant dilution, regarding the adequacy of a step in l operations procedure OP 3304C. Self-checks by operators and other plant staff were also evident in a number of condition reports (CRs) written to document the need for procedural enhancements. For instance, CR M3-98-3629 documented a shift manager's question regarding the operability of the service water system during thermal backwashing of the condenser. Since this operation was last performed, the licensee had initiated a new technical requirement that delineated the need to have two service water pumps operable for an operable service water train. The inspector reviewed the applicable technical specifications, the governing provisions of circulating water procedure, OP 3325A, and the L I
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disposition to the CR and determined that this was another example of a good questioning attitude by shif t personne l The inspector conducted a sample review of operability determinations, temporary modifications that were filed as active in the control room, and the Unit 3 Shift Lo Discussion with operations management personnel regarding the requirements of the work control procedura, WC-10, governing temporary modifications led to the issuance of CR M3-98-3771 indicating some inconsistencies in the way active and inactive temporary modifications are handled. Where the licensee issued CRs documenting component performance issues, the inspector spot-checked the technical specifications to verify proper entry into the applicable limiting conditions for operation. Inspector observation of shift briefings for operational evolutions and surveillance testing was conducted on a random l basi The inspector discussed with operations, licensing, and the cognizant engineering personnel l a question of the need for an additional steam generator tube inspection in accordance with the provision of Technical Specification (TS) 4.4.5.3.a. Since the last inspection had been started in September 1996, an additional inspection would be required by September 1998 unless the licensee initiated action to defer the inspection until the next refueling outage.-
On August 6,1998, the licensee submitted TS change request TSCR 3-17 98 to request a one-time extension of the normal 24-month surveillance interval for steam generator tube inspections. On August 11,1998, the NRC Office of NRR issued a notice of consideration of the amendment to the Unit 3 Operating Licens The inspector also reviewed the Nuclear Oversight monthly report for July - August, noting that quality assurance (QA) observations had identified a significant improvement in the performance of the Unit 3 operations staff from restart through power ascension. The inspector discussed operations performance with Nuclear Oversight personnel, specifically evaluating Oversight's assessment of performance at 100% power and routine operational surveillance (e.g., MP3-P-98-042) activities. While these QA findings indicated that further operations department improvements could be achieved, the overall conduct of operations was generally satisfactory with improving trends noted for most of the assessed performance criteria. On August 6,1998, the final overall results of the Nuclear Oversight assessment of the Unit 3 startup and power ascension program were issued. This final assessment documented the continuing challenges at the various department levels, the lessons learned by Nuclear Oversight, and going-forward plans for ongoing QA evaluations of line performance with the unit in an operating mode. The inspector discussed the overall assessment of operational performance, including the Nuclear Oversight findings and NRC observations, with the acting unit directo Based upon the continued efforts in effecting procedural improvement, as well as the demonstrated performance in monitoring and conducting proper surveillance activities, the inspector re assessed the comprehensive corrective measures taken with regard to a violation of e.e plant technical specifications documented in inspection report 50-423/97-208. Sinc ) the licensee was not required to submit a response to this violation and the corrective actions appear to have been effective, violation 50-423/97-208-04 is hereby closed.
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- 30 Conclusions Overall plant operations, including reactor startup, power operations, and licensed operator control of routine evolutions and response to emergent conditions, have been conducted in a deliberate manner. The inspector observed both a questioning attitude and a conservative approach to issues on the part of shift management. Nuclear Oversight's assessment of an improving trend in the area of operations staff performance was generally confirmed by NRC inspection observations during this inspection perio .2 Reacter Startuo Coveraae Insoection Scone (71707. 71715. 61726)
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Unit 3 was shut down on March 31,1996 and NRC Commission approval was required to permit restart of the unit. This permission was delegated to and later granted by the Executive Director for Operations on June 29,1998. Due to the extensive shutdown, the- j NRC conducted an inspection of control room and related activities from just prior to Mode' l
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2 (June 29) through 30 percent reactor power (July 7) to evaluate the licensee's performance.
Around-the-clock coverage of significant operations was conducted by the NRC resident
- staff and other inspectors. The inspectors observed operational turnovers, shift briefings, -
pre-evolution briefings, surveillances and reactivity manipulations and accompanied plant equipment operators on their rounds of various plant areas. Also, during this period, there was an NRC manager onsite reviewing licensee performanc Observations and Findinas During the course of the startup coverage, inspectors observed plant operations and surveillances conducted in accordance with portions of the following operating procedures (ops), abnormal operating procedures (AOPs), surveillances (SPs), and special procedures j (SPROCs).
OP 3202 Reactor Startup OP 3203 Plant Startup OP 3207 Reactor Shutdown
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OP 3209A Reactivity Calculations - Estimated Critical Conditions OP 3260 Unit 3 Conduct of Operations OP 3321 Main Feedwater AOP 3569 Severe Weather Conditions SP 362 Main Turbine Stop Valve Stroke Time Testing j SPROC 97-3 30 Startup and Power Ascension Sequencing Procedure i
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Observed pre-evolution briefings during the startup and power ascension were thorough and communicated the purpose of the evolution, steps to be followed, termination criteria, personnel responsibilities, use of three-way communication, peer and self checking, and procedural adherence. In addition, past experiences at Millstone and other plants were of ten described to prevent similar problems at Unit 3. The inspector observed questioning attitudes from operators during these briefings. (For example, an SRO questioned the preliminary estimated critical position (ECP) of the rods with the given boron concentratio When the calculation was subsequently independently verified, as planned and required by procedure, the ECP was revised and communicated to the shift.) Briefings noted the fact that much of the equipment had not been subjected to normal operating pressure and l temperature in over two years and stressed that any unexpected or questionable '
performance should be brought to the shift's attention promptly. Also, each briefing I emphasized that there was no time pressure and the expectation 'vas to operate the plant correctly and deliberately, event free. The inspector considered the designation of the startup as an infrequently performed evolution (IPTE), thereby requiring a management test lead, a positive management decision to focus the organization on the importance of the l startu Operators performed evolutions slowly and deliberately during the startup. Shift turnover and briefings effectively communicated plant status and plans for the shift. Three way ~
communication was generally observed for commands and two way communication for informational exchanges, as planned. Peer checking was performed and no operator errors were identified by the inspector. Operators communicated illuminated annunciators and stated whether the alarms were expected or unexpected and entered appropriate alarm
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response procedures. Although a burnt out light bulb on one of the panels was identified during a surveillance test, not the shiftly lamp check, the inspector determined that operators were aware of the boards and plant condition Operators responded well to equipment, environmental, and procedural problems. Proper entry into TS LCOs was verified by the inspector as plant equipment became inoperable due to equipment problems or required testing. The inspector confirmed that CRs were written to document problems, as required. In addition, when a tornado warning was announced, AOP 3569 was entered and associated actions taken. Operators took manual control of equipment to gain finer control during certain plant evolutions such as placing
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main feedwater in service. While several procedural problems were identified throughout the startup, in each case, operations stopped the evolution until the appropriate procedure change was made. This was not unexpected as many procedures had not been used in over two years and higher standards regarding procedural compliance had been implemented since their last us Plant equipment operators' (PEOs) performance during plant tours and equipment manipulation was good. Problems with equipment operation were typically identified and brought to the attention of the shift manager or unit supervisor. However, the inspector did note the lack of a questioning attitude in the area of boron formation on the safety injection pumps. Although leakage on these pumps is expected, operators did not request radiation protection assistance when cleaning oil leaks near the boron formations from the pumps. Subsequent analysis confirmed that no contamination was present; however l
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j 32 l during an accident these areas could become contaminated. Signs were subsequently ,
l placed at the entrance to the ESF building and on the safety injection pumps to l l appropriately draw personnel attention to the f act that these areas could become !
, contaminated. After the inspector questioned the existence of trouble reports (TRs) for the l l oil leaks being wiped up by the PEOs, TRs were generated.
i l Throughout the startup, senior management oversight and nuclear oversight presence was
- observed in the control room during significant evolutions. Both groups provided feedback l to the shift to confirm proper actions were taken during the course of the startu Conservative decision making was evident durir g the initial startup on June 30 when the B l intermediate range detector did not indicate changing reactor power. First, the shift manager decided to suspend the startup to allow l&C to troubleshoot the problem. Later, when the problem was not readily resolved, the unit director decided to shut down the l reactor while troubleshooting and repair activities were performed. After a loose connector outside of containment was identified and repaired, the operators successfully performed the second reactor startu Conclusions The licensee performed the Unit 3 startup in a controlled and conservative manner -*
following a shutdown which lasted in excess of two years. Improved operator performance since the NRC operational safety team inspection (OSTI) inspection (IR 50-423/97-83) was l noted. Appropriate actions were taken in response to equipment, environmental, and procedura problems. Operators closely followed procedures as documented by several procedural issues they identified during the startup. Plant equipment operators'
performance during plant tours was good. Problems with equipment operation were typically identified and brought to the attention of the shift manager or unit superviso Senior management and nuclear oversight maintained a strong presence in the control room. Specifically, senior management made the conservative decision to shut down the reactor after a problem was identified with one of the nuclear instrument Overall, the NRC around the-clock shift coverage noted good licensee performance l consistent with that of a plant returning from an outage over two years in duration. It was i
also consistent with other NRC operationalinspection coverage of the startup and power ascensio U3 08 Miscellaneous Operations issues (92700)
08.1 (Closed) LER 423/97-034-00: Valves not included in Containment isolation Valve (CIV) Surveillance Insoection Scone (92901)
While Unit 3 was in Mode 5, as part of a Configuration Management Program review, the licensee discovered that the Containment Manual (Outside Containment) Valve Checklist did not contain the complete ibt of manually operated CIVs that require monthly closure
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verification. The Technical Specification surveillance requirement for CIVs states that in l
.. _ _ _ . _ . _ _ _ _ _ _ . _ . . _ . _ - . _ . _ . . _ _ . ~ _ _ _ _ _ _ - _ _ _ _ . _ _ . _ Modes 1 through 4, all penetrations not capable of being closed by operable-containment-
' automatic-valves or operator action be verified closed at least once per 31 days to ensure the integrity of the containment isolation boundar The inspector reviewed LER 423/97-034-00, the list of CIVs in the FSAR, a drawing showing the location of one of the valves being removed from the licensee list of CIVs, the bill of materiallisting for one of the valves being removed from the list of CIVs, Procedure SP 36128.1, " Containment Manual isolation Valves (Outside Containment) Valve Position Verification," as well as other associated engineering documents, Observations and Findinas The licensee surveyed all containment isolation lines to determine if additional valves had been omitted from SP 36128.1. The result of all surveys was that a total of four valves were discovered to have been omitted from the CIV list. As a result of the survey, several r valve changes were made to both the interior and the exterior of the containment including the removal cf four valves from the designation as CIVs. The inspector checked one of the four removed valves and verified this valve was not listed in the FSAR as a containment valve. In addition, this valve is one of three inline valves located just outside of -
containment, with the other two of the three valves located upstream and closer to the ~
containment, and designated as CIV Conclusions The corrective actions taken by the licensee for the Containment Manual (Outside Containment) Valve Checklist, which did not contain the complete list of ma:.ually operated CIVs that require monthly closure verification are deemed to be adequate. LER 423/97-034-00 is considered closed. The failure to perform the required Technical Specification surveillances is a violation of NRC requirements. However, in accordance with the NRC Enforcement Policy, NUREG 1600, Section Vll.B.1, this is considered to be a licensee L identified, non cited violation (50-423/98 212-03).
U3.Il Maintenance U3 M1 Conduct of Maintenance l
l M1.1 Evaluation of Onacina Maintenance Activities Insoection Scone (62707)
The inspector observed maintenance planning meetings, conducted field inspections of work in progress in the plant, and reviewed work control and other governing technical documents and records to evaluate the overall performance of key emergent and selected
- maintenance activities during this inspection period. Work observations were chosen on the basis of plant status, system risk and safety significance, and the opportunity to
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l 34 Observations and Findinas The inspector specifically evaluated how new maintenance items requiring investigation and emergent work were prioritized, scheduled and tracked by the licensco's management team. The release and control of new automated work orders (AWOs), along with the handling of "fix-it-now" (FIN) team items, were assessed during maintenance meetings and in conjunction with the review of the daily scheduled activities and the coordination
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effected with the control room. Specifically, the inspector examined the following work items:
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the temperature monitoring, initial repair attempts, and final repair plan for a leaking auxiliary feedwater system valve, 3FWA*MOV35D, which is a motor operated, containment isolation valve on the disenarge piping for the motor driven auxiliary feedwater pump feeding the "D" steem generator. During the initial repair attempts )
(reference: automated work order, AWO M3-98-10697), the inspector checked that I adequate coordination and communication with the operators in the control room I had been established and that proper technical specification controls had been implemented. Also, because of the pntential for adverse effects from the back leakage and elevated temperatures upon the containment concrete and other safety related components (i.e., Target Rock valve 3FWA*HV36D sharing the same *
containment penetration line), the inspector reviewed Operability Determination (OD)
MP3104-98, Technical Evaluation M3 EV 98-0153, and a related adverse condition report (ACR M3-96-0855) to verify the affected safety system and component operability, prior to the licensee's commencement of a reactor shutdown on August 12 to repair the valv .
evaluation of the options for the main control room door repair. Because of latching problems with the door providing primary access to the control room, the licensee administratively closed this pathway to maintain the door's capability to provide a high energy line break (HELB) boundary for control room envelope operabilit Options explored for repair activities included temporary modifications, engineering changes, and regulatory relief. The inspector discussed the various options with licensee management, engineering and licensing personnel. With the decision to take the plant to cold shutdown conditions for auxiliary feedwater valve repair, discussed above, repair of the control room door was effected on August 14. With the unit in Mode 5, the technical specifications delineate control envelope conditions that permitted repair without the HELB concerns in effect in higher plant mode . completed installations and ongoing field work associated with design change record, DCR M3-97-079, temporary modification 3 98-046, and AWO M3-98-096 The inspector examined field tags on equipment for the ongoing work and required system isolations, reviewed the related design specifications and design change drawings affecting the observed field work, and verified proper liaison with the operators on shift for technical specification impact, limiting condition for operability entry and logging, and overall work control and coordination. As appropriate, safety evaluations were reviewed to confirm the acceptable screening of planned work for unreviewed safety question _- .
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post-maintenance testing of valves and containment penetrdtions. The inspector reviewed the status, field tagging, and operability / testing requirements for certain containment isolation valves (e.g., main steam and auxiliary feedwater systems)
that had been subjected to repair or other maintenance activities. Valve stroking
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criteria, in-service testing (IST) controls, and 10 CFR 50, Appendix J requirements
, and records were discussed with the cognizant maintenance and technical support personnel. Additionally, the inspector evaluated and discussed with the Office of NRR a licensee supplemental response to Generic Letter 96-06 with regard to the .
, acceptability of piping stress levels and strain limits governed by ASME Section Ill l
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requirement '
The inspector also discussed with nuclear material management and nuclear oversight personnel the current status of vendor audits and affected procurement activities, based 3 upon the takeover of Yankee Atomic Electric Company (YAEC) by Duke Engineering &
i Services (DE&S). Since the licensee had out-sourced vendor inspections to YAEC in 1995,
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the recent transition to DE&S control of these services required a re-review of the affected programmatic interfaces, roles and responsibilities, and program control and j
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implementation. Nuclear Oversight personnel indicated their plan to provide continued surveillance of off site vendor audit activities during the transition period and a future audit j of DE&S control of this program once the transition is complete. The inspector confirmed j that the licensee has assessed any impact upon the NU quality assurance program
(NUQAP) topical report that is subject to review by the NRC. Based upon these discussions, the inspector identified no concerns with current implementation of
procurement / vendor control activities and determined that Nuclear Oversight is properly j exercising its oversight function of these services.
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In another matter related to Nuclear Oversight and maintenance activities, the inspector
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reviewed a Quality Assurance Audit, MP-98-A15, of measuring and test equipment l (M&TE). The inspector observed Nuclear Oversight's determination that the M&TE j program is effective in contrc: ling affected equipment, but noted that several condition i reports were issued relative to the control of nondestructive examination (NDE) equipmen These issues were entered into the licensee's corrective action program for line organization response and subsequent Nuclear Oversight revie Conclusions Overall, the inspection of selected maintenance activities, including field observations, controlling document reviews, and the implementation of work controls, identified acceptable practices and proper coordination between maintenance personnel and the operations department. Where questions were raised regarding tagging and post-maintenance testing controls, the licensee provided adequate responses to demonstrate the acceptability of component status. Nuclear Oversight involvement in the inspection and assessment of ongoing maintenance activities and in the planning and execution of programmatic audits affecting maintenance work was evident. The inspector had no further questions regarding the implementation of maintenance controls during this inspection perio _ _ _ _ _ _ _ _ _ _ _ -
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M1.2 Station Blackout (SBO) Diesel Generator Maintenance l
l Insoection Scoce (62707)
l l The inspector reviewed the work schedule, maintenance procedures, work orders, l interviewed selected engineers and craft mechanics and observed ' maintenance work in
! progress on the station blackout (SBO) diesel and supporting auxiliary equipment to assess the preventive maintenance (PM) for the SBO diesel.
l Observations and Findinas The inspector observed work in progress on the SBO diesel and supporting equipment being performed by the licensee's mechanics, I&C technicians, the site maintenance electricians and the electricians from the Generation and Test Services (GTS) group assigned to Millstone.
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The mechanical inspection of the diesel was governed by maintenance proceoure, MP 37221 AB, Rev.0, SBO Diesel Refueling Outage Preventive Maintenance, dated April 28, 1997. The inspector found a minor discrepancy between the procedure and the vendor technical manual 25212 972-001 A for the adjustment of the hydraulic lash adjusters. The procedure failed to include a step to turn the adjusting screw 1 1/2 turns. However, the
- work was being directed by the diesel vendor's representative, not by the procedure, and the actual task performed in the field correctly included the missing procedural step. The licensee initiated CR M3-98 3723 and a procedure change for future reference in response to the inspector's finding.
l During the performance of the SBO battery maintenance, the licensee found the 125 Volt l battery showed weak voltage readings in two of the ten sub-batteries which made up the
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125 Volts. The licensee initiated CR M3-98 3650 to document the problem and immediately procured a complete replacement battery from a different manufacturer, again l consisting of ten sub-batteries of six cells each. The licensee indicated the new sub-battery model was identical to the battery already in use for the SBO computer inverte The licensee's engineering staff provided an adequate engineering evaluation to support the change of battery manufacturer based on the manufacturer's published one hour discharge i rates.
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The inspector observed the removal of the original SBO 125 Volt battery and the installation of the new battery. During removal of the original battery, the licensee noted hair line cracks on the cases of the old batteries in the area of the terminals and suspected l overtorquing during the originalinstallation by the SBO diesel supplier. The new batteries
! had a different terminal design and the new battery vendor provided recommended torque values. The inspector noted that the manufacturer's data sheet for the new battery indicated the batteries should have been installed with a % inch spacing between battery 4- cases for ventilation, however, no spacing had been specified in the installation of the new
- battery and none had been provided. in response to the inspector's concern, the licensee 1
- initiated a trouble report (TR 07M3132531) and contacted the battery manufacturer
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(Engineering Record Correspondence 25212-ER-98-0234). The inspector confirmed that
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the manufacturer agreed that, because the batteries were installed in an air conditioned room, there would be no adverse impact on the batteries if there was no spacing between the FSAR Section 8.3.1.1.5, Alternate AC Power Source Regulatory Requirements, indicated that the alternate ac power source contained a microprocessor-based control system in the l SBO switchgear enclosure for alarm and shutdown sequences which was powered from the unintarruptible power supply (UPS) to allow diesel starts up to one hour after an SB A previous NRC inspection (50-423/96-201) had identified deficiencies in the SBO l maintenance program including a lack of preventive maintenance (PM) for the SBO l computer UPS. The license ;iad issued action item 97-000597, item 2, to revise and update, as required, the SBO surveillance and maintenance procedures. The licensee l decided to address the maintanance requirements for the SBO UPS in the form of an automated work order (AWO). The inspector found that the AWO fa!!ed to address any preventive maintenance for the UPS, which consisted of a an internal 48 Volt battery, battery charger, inverter and a microprocessor for controlling the UPS. The A'NO
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documented readings taken during the simulated loss of ac input without providing any acceptance criteri Although the SBO computer UPS was not scheduled for PM during this SBO outage, the -
inspector reviewed the results from the PM performed on September 11,1997 and documented in work order AWO M3 9618284, Six Month Vendor Maintenance. The inspector discussed with the licensee the recorded data which indicated, contrary to the directions in the AWO, that there was still ac power available to the UPS during the simulated ac input line failure test. The licensee explained that the apparent discrepancies we e due to the AWO being performed immediately following installation of new larger et cacity batteries in the UPS under MMOD M3-97559 and the expectation that the post-modification testing following the replacement of the SBO computer inverter batteries would duplicate the purpose of the AWO. During the performance of the September 11, AWO, these new batteries were in fact on an equalize charge and therefore, the data recorded on the AWO did not correspond to the purpose of the AWO. That data had not l yet been reviewed by the licensee. Also, the AWO failed to reference the post-l modification test. The inspector confirmed that the post-modification test, performed a
! week after the AWO, included a two hour discharge of the inverter betteries and therefore simulated the ac input line failure in that test. In response to the inspictor's questions, the i
licensee initiated CR M3-98-3834 to address the intent of the AWO and the data recorde Following the close of this inspection period, the licensee produced the results of AWO 97-17600, performed April 13,1998, which correctly removed the ac power to the SBO UPS to r.imulate loss of the ac input lin The Station Blackout Prograin Manual is the controlling document and contains quality assurance criteria. Revision 0.c the manual was effective July 31,1997, and required instruc+3ons and procedures, including inspections and tests necessary for compliance with 10 CFR 50.63 be prescribed by documented instructions and be accomplished in 4 accordance with those documents. However, the PM instructions for the SBO UPS did not ir clode any acceptance criteria, the licensee f ailed to follow the written directions of AWO M3 96-18284, and the results had not been evaluated it should be noted that the station
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black out diesel generator is not a IE system. Thus, theses omissions appears to be a weakness in translating the requirement for PM on the station blackout diesel to an AW Following the completion of the PMs on the SBO equipment, the licensee performed a black start test using special procedure SPROC EN98-3-20, Station Blackout Diesel Generator l Startup Test, dated August 6,1998. This test simulated the loss of the rnrmal cc supply I for one hour. This servd as the acceptance test for the new battery and also re-tested the SBO UPS powering the SBO computer. The results of the test indicated that the new SBO battery successfully started the diesel after carrying the standby load for one hour. This test also proved the acceptability of the SBO UPS supply for the SBO computer. The diesel was then manually loaded to a minimum of 2260 kW and held fer 30 minutes using operating procedure OP 3346D, Station Blackout Diesel Generator. This step served as the post maintenance test for the SBO diesel. The inspector reviewed the results of these post I maintenance tests and had no further concern Conclusions The licensee successfully performed a black start test using a special procedure for the station blackout diesel generator startup testing. This test simulated the loss of the normal ac supply for one hour, and served as the acceptance test for the new battery and also re - ,
tested the SBO UPS powering the SBO computer. However, the PM instructions for the l SBO UPS failed to include any acceptance criteria; the licensee failed to follow the written l directions of AWO M3 96-18284; and the results had not been evaluated in a timely manner. This appears to be a weakness in translating the requirement for preventive maintenance on the station blackout diesel to an AW The inspector concluded that the licensee failed to identify and correct a discrepancy between the SBO diesel PM procedure and the vendor technical manual prior to performing l the task directed by the vendor's technical epresentativ The SBO UPS discrepant data recorded during a September 1997 automated work order fi!ed to reference the post-modification test which simulated the ac input line failure required by the AWO. However, the 1998 SBO post-maintenance test recorded acceptable l data for the SBO computer inverte 'J3 M8 Miscellaneous Maintenance issues M 8.1 (Closed) LER 423/97-035-00: Potential Non-Conservatism for the Steam Generator Water Level (SGWL) Low-Low Setooint due to Process Measurement Accuraev Term Uncertainties insoection Scone (92902)
A licensee Configuration Management Program review identified that the Technical Specification (TS) instrumentation settings for the SGWL Low Low setpoint were non-conservative. The ncminal trip setpoint specified in the TS requires a Channel Statistical Allowance to ensure that actuation (to trip the eactor) occurs before the SGWL reaches the low mark derived from the safety analysis limit. In 1993 while resolving a transmitter issue with these same instruments, the licensee reset the SGWL Low-Low trip point to the
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3 TS value without taking into account the conservatism required to satisfy the Channel Statistical Allowance. The licensee considered this condition to be reportable under 10
, CFR50.73 (a)(2)(ii)(B) as a condition outside the design basis.
! Observations and Findinas
, The inspector reviewed LER 423/97 035-00 and other associated engineering material As corrective action, the licensee reviewed the instrumentation requirements of the steam generator transmitters and instruments, and replaced the 18 narrow range instruments with ;
wider range instruments deemed suitable for the specified task. The new trip setpoints )
include the required Channel Statistical Allowanc l
- Conclusions Alllicensee corrective actions have been completed and are deemed adequate. LER J
423/97-035-00 is therefore considered closed.
M8.2 (Closed) LER 50-423/97-62-00 and 01: Failure to Meet Technical Soecification Definition of Analoo Channel Ooerational Test (92902)
Licensee Event Report 50-423/97-62 revisions 00 and 01 were inspected in Section I U2.M8.2 of NRC Inspection Report 50-423/98-207 and corrective actions were found to be acceptable. This LER is close U3.lli Enaineerina U3 E1 Conduct of Engineering
E (Open) URI 50-423/98-212-04: Medium Voltaae Circuit Breaker Maintenan :e Insoection Scone (92903)
i The licenseo had identified that, although they had been following the medium voltage circuit breaker manufacturer's preventative maintenance (FM) recommendations, they had not been following the manufacturer's recommendation for periodic breaker overhauls. The ;
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recommendations called for overhauls at five year intervals or 10,000 operations, whichever came first. The inspector interviewed the licensee personnel responsible for coordinating the breaker overhauls and reviewed the licensee's evaluation of the effect of the delayed overhauls and the licensee's corrective actions to assess the effect on the I reliability of the circuit breaker I Observations and Findinas The inspector observed that the licensee had questioned the original operability determinatior; (MP3-041-98) in condition report CR M3-98-2070, dated April 20,199 The licensee began to have the breakers overhauled starting with the two breakers that had ope. ting histories above the 10,000 mark. Those two breakers were origin &.y overhauled by a *ird par +y shop and were rejected by Millr tom upon receipt inspection. Tue licensee thereafter, starting in mid 1997, contracted with h eriginal breaker manufacturer's repair
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facility for overhauls on the remaining breakers and rework for the breakers that had been overhauled by the third party shop.
l i Technical Specification 4.8.4.b requires the licensee at least once per 60 months to subject each circuit breaker (protecting containment penetrations) to an inspection and l preventive maintenance in accordance with procedures prepared in conjunction with its l manufacturer's recommendations. The licensee satisfied this requirement for the reactor
- coolant pump breakers with surveillance procedure SP 3712TC, 6.9 kV Containment Penetration Breaker P The licensee had recognized that the GE Magnablast Circuit Breaker Technical Manual, l GEK-7320F, recom. mends overhauls every five years. The licensee's surveillance procedure had not acknowledged this recommendation to be part of the manufacturer's recr mmendations for inspections and preventive maintenance. However, as of January l 19b ., all of the 6900 Volt circuit breakers that were controlled by technical specifications
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for containment penetration protection had their overhauls completed. These were the first i overhauls performed on these circuit breakers in the life of the plant (18 years). The inspector discussed with the licensee why they had not considered this to be a potential technical specification violation because they had not equated overhauls to be part of the l inspection and preventive maintenance recommendations. In response, the licensee --
l initiated condition report CR M3-98-3657 to document and evaluate this concern. This l item will remain unresolved pending review of the licensee's CR evaluation (423/98-212- l 04). l The licensee's records also indicated 16 of the 39 QA medium voltage 4160 Volt circuit breakers had already been overhauled and returned. In addition, five non-QA breakers had been overhauled and upgraded to QA status. Three additional QA breakers were in the manufacturer's shop being overhauled. The remaining breakers were scheduled to be i cycled through the overhaul process as they were released by operations. The inspector reviewed General Electric (GE) letter dated May 10,1998, that confirmed that no problems were found in the overhauls that indicated any potential for common mode failure of i
breaker operation.
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I Conclusions The inspecter concluded that the licensee's corrective actions for the missed medium j voltage breaker overhauls were prudent and timely following their discovery of the missed overhaul recommendation. The inspector concluded that sufficient justification existed for breaker operability based on the GE letter that stated that no potential problems were found as a result of the completed overhauls performed to date which found no common mode failure mechanism that would interfere with plant safety. The failure to perform I period overhauls on medium voltage breakers in an Unresolved item, because the licensee had not equated overhauls to be part of the inspection and preventive maintenance i recommendations.
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i U3 E8 Miscellaneous Engineering issues
E (Closed) Violation 50-423/98-206-06: Failure to include Solenoid Ooerated Valves
. (SOVs) in the Environmental Qualification (EQ) Proararn Insoection Scone (92903)
The licensee had identified a number of safety related valves controlled by non-safety equipment in LER 96-036 wi had evaluated the consequences in evaluation M3-ERP-97-0008, Rev.1, Assessment of Safety Related Air Operated and Solenoid operated Valves i with Non-safety Related Controls, dated July 24,1997. The associated corrective action l was previously reviewed by the NRC and documented in inspection report 50-423/98-20 l That report identified inadequate corrective action in that the SOVs and associated cables had not been entered into the environmental qualification program to assure future l maintenance or replacements would be quaiified to withstand a harsh environment and a notice of violation (NOV) of 10 CFR 50.49 was issued. The inspector reviewed the licensee's response to assess their corrective action to the NO Observations and Findinas The licensee responded to the NOV in letter No. B17161, dated June 26,1998, and stated l that, based on the failure analysis and upgraded classification of the SOVs, adding the l SOVs to the electrical equipment qualification (EEQ) master !ist (EOML) was not require Howes u, the inspector confirmed that DCN DM3-00-0153-98 did add the SOVs and their associated upper limit switches to the production maintenance management sys'.sm I (PMMS) data base and identified the components as being associated with the EEQ l program. The Equipment Qua',ification Record was changed to indicate those components were 10CFR50.49(b)(2) items (non-safety related equipment whose failure could prevent accomplishment of safety functions). The DCN also indicated that the associated black cables should be replaced with EEQ qualified cables during any future rework or replacement of cables. The licensee confirmed that the installed black cables were the same as the EEQ qualified cables except for the color of the cable jacket. The inspector confirmed that loss of power to the solenoids would result in the air operated valves failing l close ! Conclusions The inspector concluded that the licensee adequately identified the relationship of the non-safety supporting components to the safety related valves by including them in the EEQ program. Based on the licensee's identification of the SOVs as 10CFR50.49(b)(2)
components in the associated plant documentation, NOV 50-423/98-206-06 is close ~ . - ~ - _ ~ . . . - . . - - . . - . - . _ _ _ - ~ . . . - . . - - . . ..--- - - -.- . .
E8.2 (Closed) LERs 423/96-019-00/01 Reactor Coolant Svstem (RCS) Power Ooerated Relief Valve (PORV) Block Valves inocerable due to Potential Structural Desion Deficiencv Insoection Scone (92903)
LERs 96-019-00/01 documented the ir. ability of Power Operated Relief Valves (PORVs)
3RCS*MV8000 A/B to perform their intended function to close and reopen under design basis accident conditions. Tests performed at Kalsi Engineering Inc. provided evidence that the valves required greater thrust to close than had been previously calculated and that damage to the valve during attempted closure under design basis conditions could prevent i later reopening of the valve. The licensee committed to inspect the valves and implement plant modifications as necessar Observations and Findings The inspector reviewed ACR M3-96-0277, DCR M3-97007 and the engineering test results I of Kalsi Engineering contained in document No.1893C Rev. O. In response to NRC Generic Letter 89-10, the referenced valves were tested and found to be deficient. During the test
. performed by Kalsi Engineering, portions of the valve broke and other portions galled. Th I licensee elected to replace the valves witn Anchor Darling valves, which meet the technical requirements and have a history of being used successfully in other facilities for similar service. A prototype Anchor Darling valve was successfully tested under design basis conditions. Both new Anchor Darling valves have been installed. This licensee-identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 423/98-212-06) ConclutCDA The actions taken by the licensee to resolve the inability of Power Operated Relief Valves (PORVs) 3RCS*MV8000 A/B to parform their intended function to close and reopen under design basis accident conditions are deemed adequate. NevrAnchor Darling valves have been tested, and installed. This licensee-identified and corrected violation is being treated as a non-cited violation. LERs 96-019-00/01 are close E8.3 (Closed) LER 423/96-020-00: Main Steam Atmosoheric Relief Valves inocerable due to Personnel Error durina Preoaration and Review of Setooint Calculation Insoection Scone (92903)
The inspector reviewed the documentation associated with Licensee Event Report 423/96-020-00. Plant personnel, while performing a scheduled rriview of thrust calculations, discovered that the summary tabits of the Design Basis Differential Pressure Calculation for all four Main Steam Atmospheric Relief Valves (3 MSS *MOV74A/B/C/D) did not include the throttle /close direction safety function stroke which was described in the body of the valve calculation. Therefore the valves were not capable of performing their intended close-safety function at the As-Left close torque switch setting _ . .. -
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l l Observations and Findinas I
The summary table of the Design Basis Differential Pressure Calculation for all four Main l Steam Atmospheric Relief Valves (3 MSS *MOV74A/B/C/D) did not include the throttle '
/close direction safety function stroke which was described in the body of the valve calculation This error was carried over to the thrust calculation, which was used to specify the test acceptance criteria. The As-Left close torque switch settings were not set high enough to meet the corrected acceptance criteria. This calculated value for the torque switches was too low to ensure that the "A", "B" and "D" vt.lves would close if required to do so under accident conditions. The setting for valve "C" was adequat The inspector reviewed ACR M3-96-0278 and associated engineering documentation. The licensee revised the Design Basis Review and thrust calculations for the referenced valve The revised minimum test acceptance criteria were incorporated into the maintenance l activity. The close-torque switches for the referenced valves were reset to attain the required margin based on the revised calculations. This licensee-identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 423/98-212-06) Conclusions The summary table of the Design Basis Differential Pressure C: :ulation for all four Main Steam Atmospheric Relief Valves (3 MSS *MOV74A/B/C/D) did r ot include the throttle
/close direction safety function stroke which was described in the body of the valve calculation for the referenced valves have been revised and the valve settings changed to meet design basis requirements. The actions taken by the licensee are deemed to be adequate. This licensee-identified and corrected violation is being treated as a non-cited violation. LER 423/96-020-00 is close EC.4 (Closed) LER 423/96-035-00: Motor Ooerated Valve Performance Outside the Desian Basis of the Plant Inspection Scoce (92903)
An evaluation on all Motor Operated Valves (MOVs) within the scope of Generic Letter (GL)
8910 was performed by the licensee to determine if the referenced MOVs would have stroked under design basis conditions. This MOV evaluation was precipitated by the NRC issuance of Information Notice (IN) 96-48 " Motor Operated Valve Performance issues".
This review ide, tified 27 MOVs that potentially may not have stroked fully under design basis conditions. The NRC Information Notice questioned the use of vendor supplied data for MOV thrust calculations in determining the actuator capability to stroke against their respective design basis conditions.
j Observations and Findinas
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The inspector reviewed ACR M3-96-0833 and other associated engineering document NRC IN 96-48 advised that the vendor recommended efficiency assumptions used in the MOV thrust / torque calculations for setting up those MOVs within the scope of NRC GL 89-
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I 10 were not conservative. The licensee revised the torque / thrust calculations for the refemnced MOVs based on the EPRI PPM program and revised the degraded voltage calculations. Valve actuator torque switches were reset based on the newly calculated setpoints. Diagnostic testing was completed. This licensee-identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 423/98-212-07) Conclusions
! An evaluation of all Motor Operated Valves (MOVs) within the scope of Generic Letter (GL)
89-10 was performed by the licensee to determine if the referenced MOVs would have stroked under design basis conditions. This review identified 27 MOVs that potentially may not have stroked fully under design basis conditions. The revisions to the calculations, the valve modifications and the static testing have been completed adequately. Thit, 'icensee-identified and corrected deficiency is being treated as a non-cited violation. LER 96-035-00 is closed.
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45 I IV Plant Sunoort (Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry Controls R Personnel Contamination Event at Unit 2 l Insoection Scoce (83729)
The inspector reviewed the records and data available regarding work performed in the Unit i 2 containment on May 23,1998. The work involved lifting of the reactor upper guide l structure (UGS) from the vessel to its storage stand in the reactor cavity. Following this work, two workers were identified as having facial contamination, which the licensee subsequently determined to have resulted in approximately 5 millirem committed effective dose equivalent (CEDE) to each worke The licensee performed an event review of the circumstances involved with this activity, including the response and actions of the Unit 2 radiation protection organizatio Additionally, the licensee commissioned an independent review to validate the findings of the licensee's event review of this occurrence. The findings and results of these reviews were examined by the inspector, including corrective actions, recommendations and root -
causes identified for this ewn? Observations and Findinas On May 23,1998, two workers were assigned as part of a work team that removed the UGS from the reactor vessel and placed the UGS in its storage configuration in the reactor cavity, using the UGS lift rig assembly. The licensee supported the work activity with a radiation work permit (RWP) established for coverage of all reactor assembly / disassembly tasks, and an ALARA review that was develop for the same task in 1996. Survey data of the UGS lift rig was obtained in April 1998, while the rig was in its storage stand and the reactor cavity was dry. The survey indicated up to 350 millirad loose surface beta / gamma contaminatio On May 23,1998, the reactor cavity was flooded to prepare for reactor disassembly, which necessarily caused the UGS lift rig to be submerged. Though previously surveyed, a potential change in the radiological condition of the lift rig was possible since it was covered in contaminated reactor cavity water. Upon being connected to the UGS, the lift rig and UGS were raised in the reactor cavity pool water to effect transfer of the UGS to the storage location. When the lift rig work platform emerged, workers were permitted to access to the work platform. However, no new surveys of the radiological conditions on the work platform were performed prior to allowing worker access to the area, (e.g., to determine changes in radiation levels, contamination levels, or hot particle presence that may have caused by previous submergence). Such surveys were reasonable under the
!~ circumstances to assure that the regulatory limits of 10 CFR 20.1201 would not be i exceeded, and to determine the presence of potential radiological hazards.
l Instead of resurveying the work area, the licensee relied on general area surveys to support the activities of the individuals who accessed the lift rig work platform. While these
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surveys (general area dose rate surveys and general area air samples) were reportedly performed at the time of the work, the licensee's report indicates that they were not documented until May 26,199 On completion of the task (i.e., removal of the UGS from the reactor vessel to its storage stand in the reactor cavity) the workers exited the containment and were frisked for contamination using portal monitors located outside the containment entrance. The two workers alarmed the portal monitors, and were found to have low level facial contamination. Due to insufficient resources to effect whole body counting at that time, the radiation protection staff determined that the contamination was not significant enough to require immediate evaluation of internal exposure. Accordingly, the workers were not r"asured for radionuclide deposition (e.g., whole body counted) until three days later on
- . >26,199 Further, the potential for internal alpha contaminat.on of the individuals was not avaluated by the licensee based on the assumption that a radiological engineering Derived Air Concentration (DAC) source term evaluation made in 1993 remained valid. The radiation protection organization accepted the validity of the 1993 DAC evaluation, even though no effort was made to verify, validate or otherwise update the technical bases since that tim Consequently, the radiation protection staff assumed that long-lived alpha contamination -
was not an exposure factor at Unit 2, and that any alpha contamination detected could be-generally accounted for as radon. The DAC calculation had last been formally reviewed l and documented in 1994. Between 1994 and May 23,1998, the reactor had periods of operations of varying lengths, and had been shut down since early 1996. No reverification of the isotopic mix of plant contamination or verification of the continued applicability of the 1993 assumptions were made between 1994 and June 16,199 On June 16,15,'-3, a new sample of contamination from the reactor cavity and UGS lift rig was obtained and analyzed, which indicated the presence of five alpha emitting transuranic isotopes. Based on this new data, the licensee estimated that each of the affected workers could have received a committed effective dose eouivalent of 5 millirem, which is a small fraction of dose limit sptcified by regulatory requirement On May 26,1998, the licensee's Nuclear Oversight (NO) staff, initiated a review of the radiological work performed during the previous weekend (including May 23,1998), and develop concerns and questions with respect to the adequacy of the radiological controls that were implemented for the USS work activity anc' the resulting personnel contamination. As a result of their review, NO identified several issues regarding the adequacy of radiological controls, and the actions taken by the radiation protection staff subsequent to the identification of the personnel contaminations. Accordingly, the NO reviewer filed a Condition Report (CR) on May 28,1998. The CR identified possible violations of NRC regulations and/or station procedures relative to the conduct of the work and the personnel contamination event. These included failure to survey for alpha radioactivity, failure to implement process or engineering controls in a potential airborne radioactivity area, failure to perform timely whole body counts on workers with facial contamination, and failure to survey the affected work area for hot particle On May 29,1998, the Unit 2 Radiation Protection Manager informed NRC Region I of the CR, and characterized its content. On June 4,1998, the NRC conducted a conference call
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with members of the Unit 2 staff, including the Unit Director, to discuss the circumstances surrounding the event and to determine what actions had been taken to resolve the issues identified in the CR. In response, the licensee committed that the event would be formally reviewed by an Event Review Team (ERT). The licensee also committed to an independent evaluation of the findings of the ER On June 21,1998, the NRC reviewed Revision 0 of the ERT final report, dated June 16, 1998. A later revision of the report, apptrved by the Unit 2 Plant Oversight Review Committee (PORC) was issued on June 25,1998. The revision contained additional clarifying information relative to characterization of the event, but no change in substanc This report concluded that the issues raised by NO in the CR were well founded, there l were weaknesses within the Unit 2 Radiation Protection Department (RPD) relative to management and supervision, and the relationship between the RPD and NO was strained and tense. The report ident!fiad several weakness and areas for improvement, and identified specific performance failures, including (1) failure to perform surveys; (2) failure i to comply with Radiation Work Permit requirements; and, (3) inadequate procedures with respect to evaluating facial contamination and establishing effective whole body counting criteria and specification Additionally, an independent assessment, conducted by an experienced and knowledgeable contractor was performed, to review the event, and the ERT findings and conclusion Results of this review included recommendations for improved guidance on documenting surveys, and the establishment of periodic reviews of the technical bases used in support of the radiation protection progra In response to these findings, on or about June 16,1998, the licensee initiated actions to develop corrective actions to address the specific program and performance weaknesses that were identifie Short-term actions, which were implemented after June 16,1998, and completed prior to the start of this inspection, included performing radiological surveys of all chin straps on head protection equipment utilized in the Unit 2 Containment (which was reported as a potential source of the facial contamination), obtaining a representative total isotopic analysis of the contamination found on the UGS lift rig work pistform, and determining the CEDE for the two contaminated workers. Other short term compensatory actions included assigning the Unit 1 RPM as an advisor to the Unit 2 radiation protection organization, and establishing improvements in pre-job briefings and radiological work controls for higher risk l work in the radiation controlled area (RCA).
Long-term corrective actions were identified, reviewed and approved for implementation by l
the Unit 2 management review team (MRT). Completion dates were scheduled before the
! end of 1998. These actions include: revisions to licensee procedures for timely performance of bioassays, including whole body counting; improved criteria and process for handling of facial contamination incidents; improved guidance and specification for radiological survey performance and documentation; enhanced training of the technical staff on intemal dose assessment; and the establishment of written instructions on performance of alpha surveys (including contamination, airborne, personnel contamination).
Additionally, the licensee initiated action to review the interf ace and working relationship
concerns between the Nuciear Oversight organization and the Unit 2 Radiation Protection Department in order to effect resolution in this are The inspector determined that while weaknesses were identified in the licensee's implementation of radiological controls, no significant personnel exposures occurred as a resul CFR 20.1601 requires, in part, that the licensees make or cause to be made surveys that may be necessary to comply with the regulations in 10 CFR Part 20 and are reasonable under the circumstances to evaluate the extent of radiation levels and the potential hazards that could be present. 10 CFR 20.1201 provides occupational exposure lin.its.10 CFR 20.1204 requires determination of internal exposure The licensee's failure to: (1) make or cause to be made surveys of the UGS lift rig work platform as necessary to comply with the requirements of 10 CFR 20.1201, relative to determining actual radiological conditions in the affected work area (i.e., radiation levels, the extent of loose surface contamination, and the extent of hot particle contamination; and (2) make ar cause to be made surveys to determine potential internal exposure to two individuals with respect to suitable and timely measurements of the quantity of radionuclides in the individuals as necessary to comply with the requirements of 10 CFR 20.1204, constitutes a violation of 10 CFR 20.1501, which requires, in part, that surveys be made to show compliance with NRC regulations and are reasonable under the circumstances, in view of the fact that these matters and the findings of this inspection demonstrate that the criteria specified in NRC Enforcement Policy, Section Vll.B.1 were met, these violations are considered non-cited. (NCV 50-336/98 212-08)
The licensee's failure to initially document and maintain the surveys that were made on May 23,1998, to support radiological work on the UGS, as required by 10 CFR 20.2103 constitutes a violation of minor significance and is not subject to formal enforcement actio Conclusions Licensee review and assessment of work activities conducted in the Unit 2 reactor cavity on May 23,1998, determined that radiological controls and radiation protection practices l were not in compliance with regulatory requirements and licensee management expectations, and that weaknesses existed in the management of the radiation protection organization. While the findings resulted in the identification of a non-cited violadon, with respect to survey performance, comprehensive corrective actions were initiated to effect resolution of the licensee-identified issues.
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l l R1.2 Imolementation of the Radioactive Liould and Gaseous Effluent Control Proarams Insoection Scoce (84750-01)
The inspection consisted of the following activities: (1) a tour of selected site areas; (2)
review of liquid and gaseous effluent release permits; (3) review of selective effluent control procedures; (4) review of the 1996 and 1997 Annual Radioactive Effluent Reports; and (5) review of the Offsite Dose Calculation Manual (ODCM).
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49 .Q.bservations and Findinas The inspector toured the Unit 3 control room and selected station areas and reviewed celected radioactive liquid processing facilities and equipment, the effluent / process radiation monitoring systems (RMS), the turbine and reactor buildings for plant air balance, and air cleaning systems. All effluent radiation monitors and air cleaning systems were operable at the time of the plant tour.. The turbine and reactor buildings were maintained at a negative pressur /
Radioactive liquid and gaseous effluent release permits were complete, including projected doses to the public. Monthly dose projections were also complete, as required by the TS/ODC The reviewed effluent control procedures were detailed, easy to follow, and ODCM requirements were incorporated into the appropriate procedures. There were no unplanned radioactive liquid and gas releases in 199 The 1996 and 1997 Annual Radioactive Effluent Reports provided data indicating total released radioactivity for liquid and gcseous effluents from all units, as well as each uni .lhe assessment of the projected maximum individual doses resulting from routine -
radioactive airborne and liquid effluents were included, as required. Projected doses to the public were well below the Technical Specification (TS) limits. There were no anomalous measurements, omissions or adverse trends in these report The ODCM provided descriptions of the sampling and analysis programs, which were established for quantifying radioactive liquid and gaseous effluent concentrations, and for calculating projected doses to the public. All necessary parameters, such as effluent radiation monitor setpoint calculation methodologies, and site-specific dilution factors, were listed in the ODC Conclusions The licensee maintained effective radioactive liquid and gaseous effluent control programs in that: (1) effluent control procedures were sufficiently detailed to facilitate performance of all necessary steps; (2) the TS/ODCM requirements for reporting effluent releases and projected doses to the public were effectively implemented; and, (3) the ODCM contained sufficient specification, information, and instruction to acceptably implement and maintain ,
the radioactive liquid and gaseous effluent coritrol program R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Calibration of Unit 3 Radiation Monitorina Systems (RMS): Flow Rate Manitors and Hvdroaan Monitor 3- Insoection Scone (84750-01)
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The inspectors held discussions with system engineers and chemistry staff, conducted a tour, reviewed the most recent calibration results for the following selected effluent and process RMS and associated flov, meters to determine whether TS requirements and
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UFSAR commitments were properly implemented. Additionally, maintenance rule action
. plans were reviewe BMS e Liquid Waste Monitor; Waste Neutralization Sump Effluent Line Monitor; o Steam Generator Blowdown Monitor; e Turbine Building Floor Drains Effluent Line Monitor; e Ventilation Vent Stack Noble Gas Monitors (Normal and High Ranges);
o SLCRS Normal and High Range Noble Gas Monitors; e Engineering Safeguards Building Noble Gas Monitor; e Containment RSC Leakage Detection (Particulate and Gaseous); and I e Fuel Storage Pool Area Monitor Flow Rate Monitors e Liquid Waste Effluent Line Monitor; e Waste Neutralization Sump Effluent Line Monitor; e Steam Generator Blowdown Effluent Line Monitor;
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e Ventilation Vent Stack Flow Rate Monitor; and e Engineering Safeguards Building Discharge Flow Rate Monitor, i- Hvdroaan Monitors l e Containment Hydrogen Monitors Observations and Findinas The l&C Department maintained the responsibility of performing the electronic and radiological calibrations and functional tests for the above effluent / process / area RMS; and channel calibrations of the flow rata monitors and hydrogen monitors. All calibration results reviewed were within the acceptance criteria as defined by the licensee's procedures. The inspectors' review of licensee data indicated that RMS were responding in a linear manner. Licensee's tracking and trending efforts provided sufficient information to assess system performance.
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l As a result of self-assessment initiatives, the licensee developed and implemented an
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action plan to improve RMS reliability. Several actions items from the RMS action plan had
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been cornpleted and the licensee was actively engaged in efforts to complete remaining items.
I c.' Conclusions
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The licensee established, implemene, and maintained an effective radiation monitoring system program with respect to electronic calibrations and radiological calibrations. As a
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result of self-assessment initiatives, the licensee implemented efforts to improve radiation j- monitoring system reliability, Licensee tracking and trending efforts provided sufficient
- information to assess RMS performanc .
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R2 2 Unit 3 Air Cleanino Systems insoection Scooe (84750-01) I The inspection consisted of a review of the licensee's most recent surveillance testing results (visual inspection, in-place HEPA and charcoal leak tests, air capacity tests, j pressure drop tests, and laboratory tests for the iodine collection efficiencies) for the 4 following systems:
e Auxiliary Building Filter System; e Control Room Emergency Ventilation System; e Fuel Building Exhaust Filter System; and e Turbine Building Exhaust Filter Syste The review was against criteria contained in the TS cnd applicable document Observations and Findinas
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Ali surveillance results were either within the TS acceptance criteria or the administrative l acceptance criteria. The responsible individual had good knowledge of testing -
methodologies and acceptance criteri Conclusions The licensee established, implemented, and maintained an effective ventilation system surveillance program with respect to charcoal adsorption surveillance teste, HEPA mechanical efficiency tests, and air flow rate test R7 Quality Assurance in Radiological Protection and Chemistry Activities Insoection Scone (84750-01)
The following QA Audits were reviewed:
- MP-97-A07-06, Environmental Programs Audit; and a M 3-97-A10-06, Radiation Protection (RETS, REMP, & ODCM) and inplant Radiation Monitoring (Unit 3).
The inspection also consisted of review of the: (1) implementation of intra-laboratory measurement comparisons; and (2) implementation of the Unit 3 chemistry laboratory
_ quality control program for radioactive liquid and gaseous effluent samples, Observations and Findinas The audit findings did not identify any significant regulatory or safety issues. However, findings and recommendations wers identified to improve program performance. The response to audit findings was timely. The scope and technical depth of the audit were
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sufficient to assess the quality of the radioactive liquid and gaseous effluent control programs. Individuals with experience in radioactive effluents control and chemistry participated as audit team member The Duke Engiaeering and Service's Environmental Laboratory (DESEL) established a QA Support Program :n 1985 to provide test samples for validation of effluent radioanalytical measurements made by th( icense . The QA Support Program consisted of the quarterly distribution of test or quality control samples and issuance of a performance evaluation raport. The licensee participated in the QA Support Program. The QA samples were: (1)
tritium in water; (2) mixed gamma emitters in water and air filters; and (3) charcoal cartridges. A similar program was established by the Teledyne Laboratory and QA samples were: (1) gross alpha; (2) iron-55; and strontium-89/90. Two hundred and ninety-seven radiological effluent and environmental QC samples were analyzed annually and all measurements were within the licensee's acceptance criteria, with the exception of several gross alpha analyses. The rooi ause of the disagreement, which was statistical in nature, was evaluated and resolved by t. licensee. This had no safety significanc Quality control charts for the gamma spectrometry counting efficiency, gamma spectrometry full-width-half-maximum, and tritium counting efficiency were frequent ly reviewed by licensee staff and used as a mechanism to assess laboratory performance ' Conclusions The licensee established, implemented, and maintained an effective quality assurance program for the radioactive effluent control program with respect to audit scope and deptt, audit team experience, and response to audit findings. The licensee also implemented an effective quality control program to validate measurement results for radioactive effluent sample F2 S'atus of Fire Protection Facilities and Equipment F Fire Seal Walk-down (Unit 3) Insoection Scoce (64704)
The NRC inspector and the Unit 3 fire barrier penetration seal engineer walked-down and visually inspected accessible fire seals in the cable spreading room, auxiliary building, instrument rack room and the ESF building for physical damage, shrinkage, and seal separatio Observations and Findinas The inspector walked-down and inspected approximately 50 fire barrier penetration seals and found the conditions of most of the seals to be satisfactory. The inspector found two seals with cable tray penetrations that had voids approximately % inch square by 5 inches 1 deep which were located on the underside of the upper curl of the cable tray side rails.
l These voids were located at penetration EWE 38 of map 25212-24279 sheet ES028A and i _ -,
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EWE 55 of map 25212-24279 sheet ES034A. These seals did not meet the minimum 1 design depth of the typical detail which prescribes an installed seal depth of 24 inches and )
the minimum design depth of 22 inches. The licensee determined that the seals were still operable based on the CTL fire test dated May 1983, (FMR OAOQ3.AM), which establishes that 12 inches of silicone foam without damming will maintain a 3-hots fire ratin The licensee did not undertake any immediate corrective actions based on the available qualification fire test. The licensee determined that this condition existed from the original installation. The licensee initiated Condition Report CR M3-98-3230 to identify the condition and to track the corrective actions. The licensee initiated Trouble Reports 02M3092130 and 02M3093947 to track the seal repair I Conclusion l The inspector concluded that, with the exception of the two seals noted, all of the inspected seals were satisfactory with regards to physical damage, shrinkage and separation. The inspector also concluded that the licensee took the appropriate actions upon the discovery of the two faulty seat F3 Fire Protection procedures and Documentation F Silicone Foam Fire Pers w a Seal Audit Insoection Scoce (64704)
The licensee conducted an audit of silicone RTV foam fire penetration seals, installed between 1986 and 1991, to determine if expired materials were used during the installations. To independently verify the results of the audit, the inspector reviewed approximately 70 of the silicone RTV foam fire penetration seal work orders, licensee self audit results, and interviewed a Quality Controls (QC) inspector and senior construction representative involved with seat installations during the period of 1986 to 199 Observations and Findinas The inspector fcund that the licensee conducted a detailed audit of silicone RTV foam fire penctration seals, installed betd,een 1986 and 1991 by retrieving and comparing the material batch / lot numbers, along with their corresponding material expiration dates from the certificate of conforrnance (C/C) and the certificate of analysis (C/A), to the installation dates and finalinspection dates. In all cases, the date of the sealinstallation and final inspection was found to be prior to the material expiration date. The material shelf life expiration date was defined as 12 months from the date of shipment / analysis as identified on the C/A, and 24 months from the date of manufactur The inspector found two examples of failure to follow fire barrier seal installation
, procedures. In the first example, work order M3 8712522 (temporary sealinstallation penetration CBEW-34), Disposition Details for NCR No. 387-109, required a cerablanket seal depth of approximately 15 inches. The installed depth, as documented on the QC
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Final Inspection Record (Figure 2) of the, NUSCO Generating Construction Work Procedure No. BC S-E-6, Installation of Firestops and Seals, was only 12 inches. Although the ,
licensee's testing shows the minimum required depth for the desired fire rating was 8 '
inches, no engineering disposition was conducted to reconcile the as designed cad as installed configuration.
The second example, work order M3 8713158 (penetration EFC 41 A), Disposition Details for NCR No. 387-110, required the seal to be reworked to the detalis specified in PA 86-l 098 (original requirements). Per the drawing, a quarter inch GE-RTV adhesive sea, is :
required between the fire barrier and the penetration seal. The use of GE-RTV adhesive was not documented, as required, on the QC Final inspection Record (Figure 2) of the NUSCO Generating Construction Work Procedure No. BC-S-E-6, Installation of Firestops and Seals. The licensee determined that the fire rated RTV adhesive is a seal enhancement and does not pose an operability issue. The seal is located behind the cable tray cover for 3TX 404R and was not accessible for inspection. The licensee has issues PMMS Trouble Report (TRS No. 01M3151334) to remove the cover and inspect the seal to determine if it meets design specifications.
Technical Specification (TS) 6.8.1.a requires that written procedures be established, implemented, and maintained covering activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. TS 6.8.1.a applies to the installation of Firestops and Seals procedure. The failure to install a seal in accordance with the disposition details and the failure to install a seal in accordance with the design details were violations of TS 6.8.1.a. This failure constitutes a minor violation and is not subject to formal enforcement action. Conclusion The inspector concluded that the licensee conducted a detailed self audit and that no evidence of expired material usage was found. The inspector identified one minor violation, with two examples which resulted from the failure to follow fire barrier seals installation procedures.
F4 Fire Protection Staff Knowledge and Performance F Fire Penetration Seal Insoection (Unit 3)
l Insoection Scoce (64704)
I The inspector reviewed the Fire Penetration Seal Inspection procedure, document number SP 3641D.4. The inspector observed a sample of the silicone RTV foam inspections conducted by the assigned fire brigede members in the Millstone Unit 3 instrument rack room. This inspection was conducted to independently verify the licensee's conduct of the 18 month fire barrier surveillance, as delineated in the Northeast Nuclear Energy's letter to the NRC dated June 29,199 . . . _ . _ _ _ _ _ . _ _ _ . . _ _ _ _ . _ ._. ___
l Observations and Findinos 1 The inspector found that the fire brigade members were knowledgeable about the fire barrier sealinspection procedure and acceptance criteria. The sample of seals that was inspected by the fire brigade in the inspector's presence was found to meet the acceptance criteria specified in section 4.2.2 of SP 3641D.4. The acceptance criteria required a visual inspection of each seal to ensure the following: Seal is in place Seal is flush with surrounding ccqdui Seal has not been damaged or aitere Seal deterioration does not exceed the inspection requirements listed in Attachment 3. This attachment required, for silicone foam, no cracks or gaps in the seal surface greater than 0.25 inches wide by 1.75 inches deep (length does not matter) or greater than 1 square inch by 0.5 inch deep, Conclusion The inspector concluded that the fire brigade members were thorough and professional in +-
the execution of the Fire Penetration Sealinspection, document number SP 3641 l F7 Quality Assurance in Fire Pretection Activities F Fire Barrier Penetration Seal Installation (Unit 2) 1 1 insoection Scoce (64704)
l The inspector observed the installation of a fire barrier penetration seal at penetration i SEXD1 at Millstone Unit 2. The inspector reviewed the installation procedure, interviewed I the installer and Quality Controls (OC) inspector, and monitored the installation activities on l both sides of the penetratio l l Observations and Findinas
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The inspector found that the installer was knowledgeable about the installation procedure, document number CMP 718F, and the manufacturer's installation instructions. The QC inspector verified the silicone foam cartridge lot number and expiration date as required by
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section 4.5.3 of the installation procedure. He properly executed all of the required hold
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, point inspections in accordance with the procedure.
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' Conclusion
- . The NRC inspector concluded that the fire barrier penetration seal was installed and inspected in accordance with the installation procedure, document number CMP 718F, and l the manufacturer's installation instructions. The licensee's QC inspector was knowledgeable of the procedural requirements and was properly traine ,
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F7,2 Silicone RTV Foam Color and Cell Structure Surf ace Insoection (Unit 3) Insoection Scoce (64704)
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The inspector observed approximately 10 of the random color and cell structure inspections of silicone RTV foam fire seals performed by QC in the instrument rack room (middle aisle) ;
floor and the Auxiliary Building. He also reviewed inspection criteria as defined in AWO j M3-9810793 and the completed inspection results, Observations and Findinas The inspector found that QC conducted a thorough and professionalinspection of the fire barrier penetration seals. QC identified housekeeping deKciencies in the instrument rack ;
room (middle aisle) floor and promptly corrected the conditiort. All of the witnessed seal I inspections were acceptable or optimum with regards to color and cell structure. The j inspector found, through review of the inspection results, that all of the fire barrier I penetration seals that were inspected were satisfactory with regards to color and cell structure.
f Several minor cosmetic deficiencies with the seals were identified by the NRC during the -
inspection. These deficiencies were properly documented by QC QC did determine that one penetration seal, EWE 04, was inoperable due to physical damage to the toam (hole approximately 1 inch deep). The licensee issued CR M3-98-3244 and established a fire watch for the seal as a compensatory measure, Conclusion The inspector concluded that all of the silicone RTV foam fire barrier penetration seals inspected were satisfactory with regards to color and cel! structur V. Manaaoment Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at separate meetings in each unit at the conclusion of the inspection. The licensee acknowledged the findings presente X ) .1 Final Safety Analvsis 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 UFSAR commitments. All reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures and parameter . - . - . .. . .- . . ._. . . _ - . _ . - . . . - _ . . . - . . . - . _ . . - _ While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The following
, inconsistency was noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspectors:
e Section 14.2 of the Millstone Unit 2 FSAR did not clearly identify closure of a single main steam isolation valve as the bounding event for secondary (steam) side pressure.
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58 INSPECTION PROCEDURES USED IP 37001 Design Changes and Modifications l
IP 37551 Onsite Engineering IP 61707 Determination of Reactor Shutdown Margin i IP 61726 Surveillance Observations I IP 62707 Maintenance Observations IP 64704 Fire Protection Program IP 71707 Plant Operations IP 71715 Sustained Control Room and Plant Observation IP 83729 Occupational Exposure During Extended Outages IP 84750/01/02 Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 92700 Onsite follow-up of Written reports of Nonroutina Events at Power Reactor Facilities IP 92901 Followup - Plant Operations IP 92902 Follow-up Maintenance IP 92903 Follow-up Engineering i i
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ITEMS OPENED, CLOSED, AND DISCUSSED Onened 50-336/98 212-01 NCV Surveillance Procedure Bypasses Wrong Radiation Monitor Annunciator (U2.M8.2)
50-423/98 212-02 NCV Turbine Driven Auxilary Feedwater Pump surveillance testing (U2.M8.3)
50-423/98 212-03 NCV Valves not included in Containment isolation Valve (CIV)
Surveillance (U3.M8.3)
50-423/98 212-04 URI Medium Voltage Circuit Breaker Maintenance (Section U3.E'l.1)
50-423/98-212-05 NCV RCS PORC Block Valves (Section U3.E8.2)
50-423/98-212-06 NCV Main Steam Atmospheric Relief Valves Inoperable (Section U3.E8.3)
50-336/98-212-07 NCV MOV Performance Outside Design Basis (Section U3.E8.4) !
50-336/98-212-08 NCV Failure to perform radiological surveys in accordance with ;
10 CFR 20.1501 (Section IV.R1.1) i Closed l l
DEV 50-336/94-201-06 Section U2.E I IFl 50-336/98-201-16 Section U2.E I
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eel 50-336/96-201-11 S6ction U2.E eel 50-336/96-201-31 Section U2.E VIO 50-423/97-208-04 Section U3.0 )
VIO 50-423/98-206-06 Section U3.E Discussed 4 eel 50-336/97-02-12 Section U2.M8.1
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VIO 50-336/96-08-07 Section U2.M eel 50-336/96-201-42 !
&43 Section U2.E I The followina LERs were also closed durina this insoection:
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Unit 2:
97-013-00 U2.M U2.M /01 U2.E Unit 3:
97-034-00 U3.08.1 i 97-035-00 U3.M 8.1
- 97-062-00/01 U3.M /01 U3.E8.2 4 96-020-00 U3.E8.3
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96-035-00 U3 E i
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- LIST OF ACRONYMS USED ACR(s) adverse condition report (s) i AFW auxiliary feedwater ALARA as low as reasonably achievable AOP(s) abnormal operating procedure (s)
AWO(s) automated work order (s)
BTP branch technical position C/A~ certificate of analysis C/C certificate of conforrnance CEDE committed effective dose equivalent CFR Code of Federal Regulations i CIV(s) - containment isolation valve (s) l CMP configuration management plan / project j CR(s) - condition report (s) !
-DAC derived air concentration DBDP(s) design basis documentation package (s)
DBS design basis summary DCN(s) ' design change notice (s)
DCR- design change record
' DESEL Duke Engineering & Services Environmental Laboratory DRS Division of Reactor Safety
' ECP estimated critical position EDG(s) emergency diesel generator (s)
EDO Executive Director of Operations eel (s) escalated enforcement item (s)
EEQ electrical equipment qualification EPRI Electric Power Research Institute ,
EQ environmental qualification E O M L- equipment qualification master list ERT event review team -!
. ES emergency safeguards facility FSAR Final Safety Analysis Report GDC general design criterion / criteria GE General Electric GL Generic Letter gpm gallons per minute HELB high energy line break HEPA high efficiency particulate ICAVP Independent Corrective Action Verification Program IFl inspector follow item IPMP integrated preventive maintenance program
- lPTE infrequently performed evolution IRM(s): intermediate range monitor (s)
kV kilovolt LCO limiting condition for operation LER(s) licensee event report (s)
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r - ---- _ - - * ,w yr se- +w -
LOEL- loss of electricalload MEPL(s) material, equipment, and parts list (s)
MMOD maintenance modification MOV(s) motur operated valvefs)
MP(s) maintenance proceh.e(s)
MRT . management review team MStV main steam isolation valve i MSSV main steam safety valve NCR(s) nonconformance report (s)
NCV non-cited violation
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NDE non-destructive examination
. NGP(s) nuclear guidance procedure (s)
NO Nuclear Oversight 1 NOV(s) Notice of Violation (s)_
NRC Nuclear Regulatory Commission .
- NRR Nuclear Reactor Regulation
] NSR nonsafety-related NU Northeast Utilities 1
. NUQAP Northeast Utilities Quality Assurance Program l 4 OCA Office of Congressional Affairs
.ODCM . Offsite Dose Calculation Manual OEDO Office of Executive Director for Operations OP(s) operating procedure (s)
ORA Office of the Regional A'dministrator 1 OSTI operational safety team inspection l PAO ' Public Affairs Office PDAC Predecommissioning Advisory Committee PEO plant equipment operator PM preventive maintenance FMMS production maintenance management system ,
PORC plant operation review committee I PORV(s) power operated relief valve (s) l PSDAR Post-Shutdown Decommissioning Activities Report !
QA quality assurance ,
QC quality control 1 RBCCW reactor building closed cooling water RCS reactor coolant system REMP Radiological Environmental Monitoring Program RETS Radiological Effluent Technical Specifications RG~ Regulatory Guide RMS Radiation Monitoring System RP& radiological protection & chemistry RPD Radiation Protection Department
.RWP(s) radiation work permit (s)
RWST - refueling water storage tank
.SBLC standby liquid control SBO station blackout
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SGWL steam generator water level
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SIL significant item list SLCRCS supplementary leak collection and release system SOV(s) solenoid-operated valve (s)
SP(s) surveillance procedure (s)
SPDS safety parameter display system SPO Special Projects Office SPROC special procedure TDAFWP turbine driven auxiliary feedwater pump TR(s) trouble report (s)
TRM Technical Requirements Manual TS(s) technical specification (s)
TSCR(s) technical specification change request (s)
UFSAR updated final safety analysis report UGS upper guide structure URl(s) unresolved item (s)
VIO violation YAEL Yankee Atomic Environmental Laboratory l
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