IR 05000245/1997208
| ML20203H116 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/25/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203H085 | List: |
| References | |
| 50-245-97-208, 50-336-97-208, 50-423-97-208, NUDOCS 9803030159 | |
| Download: ML20203H116 (53) | |
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i U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION SPECIAL PROJECTS OFFICE Docket Nos.:
50 245 50 336 50-423 l
Report Nos.:
97 208 97 208 97 208 License Nos.:
DPR 21 DPR-65 NPF 49 Licensee:
Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06385 Facilhy:
Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at:
Waterford, CT Dates:
December 1,1997 - Decemb6 31,1997 Inspectors:
T. A. Eastick, Senior Resident inspector Unit 1
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D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Corne, Senior Raident inspector, Unit 3 P. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident Ir:spector, Unit 2 B. E. Korona, Resident inspector, Unit 3 L. L. Scholl, Reactor Engineer, SPO J. Higgins, NRC Contractor P. Bezier, NRC Contractor A. Fresco, NRC Contractor S. M. Wong, NRC Contractor Approved by:
Jacque P. Durr, Chief Inspections Branch Special Projects Office, NRR
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9003030159 900225 PDR ADOCK 05000245
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TABLE OF CONTENTS EX E C U TIV E S U M M A RY............................................. lil U1.1 Operations
..................................................1 U101 Conduct of Operations............................... 1 U 1.ll M aint enan ce............................................
.3 U1 M1 Conduct of Maintenance.........................
.3 U1 M4 Maintenance Staff Knowledge and Performance............. 5 U1 M8 Miscellaneous Maintenance issues....................... 6 U 1.lil Engineering................................................ 9 U1 E7 Quality Assurance in Engineering Activitles................. 9 U2.1 Operations
.................................................11 U201 Conduct of Operations.............................. 11
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U 2.ll M aint enance................................................ 12 U 2 M *.
Conduct of Maintenance............................. 12 U2 M3 Maintenance Procedures and Documentation.............. 14 U 2. lli Engineering................................................ 1 5 U2 E1 Conduct of Engineering.............................. 16 U2 E8 Miscellaneous Engineering issues....................... 16 U3.1 Operation'
...............................................21 U3 01 Conduct of Operations.............................. 21
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U3 04 Operator Knowledge and Performance................... 22 U3 07 Quality Assurance in Operations............
..........24 U 3.ll M aintenance................................................ 2 6 U3M1 Conduct of Maintenance............................. 26 USM2 Maintenance and Material Condition of Facilities and Equipment. 27 U3 M7 Quality Assurance in Maintenance Activities............... 30
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U 3.lli Engineering................................................ 3 4 U3 E1 Conduct of Engineering................................',4 U3 E2 Engineering Support of Facilities and Equipment............ 36 i
U3 E3 Engineering Procedures and Documentation
...............38 U3 E8 Miscellaneous Engineering Issues...................... 39 IV Plant Support
.................................................42 R1 Raolologient Protection and Chemistry Controls............. 42 R2 Status of Radiological Protection and Chemistry Facilities and Eq ui pm e nt....................................... 4 3 V. M::nagement Meetings........................................... 43 X1 Exit Meeting Summary.............................. 43
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i EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/97 208; 330/97 208;423/97 208 Operations i
At Unit 1, the NRC determined that while successful monthly surveillances indicated e
the emergency gas turbine generator was capable of burning korosine, the licensee's lack of timeliness in the identification of the discrepancy between the purchase order fuel requirements (aviation fuel) and the acceptance, storage, and use of korosine fuel oil, as well as the lack of timeliness in taking immediate or interim corrective actions is c..isidered a weakness. In addit:on, the conflicting fuel specifications that support various licensee procedures and processes, as well as the inability of the licensee to adequately determine the exact fuel that is required for use in the gas turbine is considered unresolved. (Section U1.01.2)
At Unit 2, overall operator performance during the inspection period continued to be
very good Changes in plant conditions to support maintenance activities were well controlled and event free. (Section U2.01.1)
At Unit 2, the licensee issued a prompt report when both service water trains were
declared inoperable when a 6 inch by 12 inch piece of plasticized polyvinyl chloride -
(PVC) piping liner material (Arbosol) was found in th6 wvL:e water strainer basket to the "B" emergency diesel generator (EDG) heat exchanger. At the end of the inspection period, the licensee's liner inspections of the "A" service water piping, which had been previously cross connected to cool the "B" EDG, did not locate the origin of the piece of liner. At the end of the inspection period, NRC and licensee
evaluation of this concern was ongung and will be covered in a future NRC inspection report. (Section U2.01.1)
At Unit 3, a number of operational procedures may still require revision as a result of
condition report dispositions, the approval of pending license amendment requests, and continuing CMP review activities. Implementing the needed changes, in
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addition to familiarizing the plant operators with the new requirements merits continued management attention. (Section U3.01.2)
Corrective actions to address specific and generic concerns with verbatim
compliance with Unit 3 technical specifications were detr.rmined to be comprehensive. (Section U3.04.1)
At Unit 3, the NRC identified a problem in the area of operator training during a
review of Rosemount transmitter shipping plug corrective actions. Although part of the licensee identified corrective actions for this issue included added operations personnel training, this training had not been perform <3d when the item was closed.
The required training was subsequently completed. (Section U3.M2.2)
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Malntenance The licensee's performance of a Unit i standby gas treatment system (SBGT)
surveillance was good. However, the licensoo failed to identify the effect the SBGT system status would have on the performance of the surveillance. Specifically, the pre job brief should have addressed the SBGT system " lockout" status and the need to place the system in a condition that would allow successful completion of the surveillance using the approved procedures, in addition, notwithstanding the f act the SBGT system status was not adc'ressed in the pre job brief, the operator should have recognized the need to place the SBGT system in " normal" to successfully start the applicable f an. (Section U1.M1.1)
At Unit 1, the performance of a core spray system surveillance was alsn good.
(Section U1.M1.2)
Unit 1 line management and nuclear oversight worked on a collaborative effort to
develop a practical training " mock up" that is being used to evaluate and provide feedback to management individuals who perform work observations. The mock up incorporates over 100 actual deficiencies that were identified in condition reports and work observations. This innovative training methodology is an excellent management tool for reinforcing higher standards for work performance in the plant, and also provides an additional opportunity for participants to learn from one another. Feedback from the participants has been very favmable. (Section U 1.M4.1 )
At Unit 2, the inspector found tha; the surveillance procedure for the wide range
nuclear instrument (NI) drawer calibration uses a test input from a pulse generator that hca an output of as high as 10 Vdc when the normalinput into the wide range NI drawer is only 0.02 to 0.2 Vdc. The licenseo stated that the high test voltage would not damags any drawer components and should not have adversely affected previous calibrations. The NRC considers the issue unresolved. (Section U2.M1.1)
At Unit 2, the NRC observed two instances where maintenance, opert.tlons, arid
instrumentation and control personnel demonstrated a high standard regarding compliance with surveillance procedures when the surveillance tests were halted in order to implement changes to unclear procedures, in one instance, the surveillance was part of a critical path activity. (Sections U2.M1.2 and U2.M1.3)
At Unit 2, the licensee's program to inspect various installed plant instrumentation,
including Rosemount transmitters, to insure shipping material had been removed was found to be acceptable. The licensee's inspections are ongoing..Section U3.M2.2)
Several Unit 3 corrective actions reviewed this period for varinus problems involved
procedure changes, in each case, the deficient procedures were identified and iv
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appropriately revised to prevent future problems. (Sections U3.04.1, M7.1, M7.2, E2.1)
The licensee's root cause assessment and corrective action vere thorough and
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I provided an appropriate resolution to the Unit 3 reactor coo; ant pump number one
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seal hous.ng bolt leakage and bolt corrosion problems. (Section U3.M2.1)
Engineering The lack of trending NCRs and verifying the effectiveness and adequacy of the ACR
database by the QA department, Unresolved item (URI) 95 81 01, was generated from the Millstone Safety Assessment and independent Oversight Team inspection that occurred on all three Mil l stone units in September and October of 1995. All units now issuo quarterly Corrective Action Program trend reports. While the link between the requirement to trend NCRs and the Unit 1 CR process is not well-defined, it appears to adequately address this URI (Section U1.E7.1)
At Unit 2, the f ailure to restrain temporary equipment within the control room as
specified in site-wide administrative procedures created the potential for adverse seismic interactions affecting safety related equipment. This failure to comply with procedures to preclude potential seismic interactions constitutes a violation of 10 CFR 50, Appendix B, C iterion V, with regard to implementation of the Northeast Utilities Quality Assurance Program. (Section U2.E1.1)
At Unit 2, a review of the Material, Equipment, and Parts Lists (MEPL) program
found that the licensee has not yet developed acceptable, broader corrective actions to address past instances where non safety related parts were inappropriately installed for parts with no MEPL evaluations that were classified as " Undetermined" or "Non Safety Related." In addition, when previously installed parts have been upgraded to " Safety Related", the licensee was not providing sufficient justification when the non-conformance report disposition was "use as is." Although this report primarily discur,es two specific aspects of the MEPL program, other broader aspects of the program discussed in previous inspection reports remain open.
(Section U2.E8.1)
The licensee's corrective actions to heighten employee awareness of the importance
of technical specifications and their proper consideradon in determining compliance with 10CFR50.59 and te redress the source of an apparent Unit 3 violation concerning turbine driven auxiliary feedwater design concerns were positive and appropriate. (Section U3.E1.1)
At Unit 3, the NRC noted examples of incomplete licensee followup to implement
changes to operational procedures required by corrective action to a charging pump overcooling problem. Corresponding with this, control room operators had not been trained to respond to adverse conditions associated with the postulated f ailure scenario. (Section U3.E2.1)
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e At Unit 3, the licensee has implemented comprehensive corrective actions to ensure i
that safety related logic circuit surveillance procedures are adequate to fulfill
technical specification testing requirements. Hnwever, the failure to have adequate
surveillance procedures to test the safety related logic circuits, as initially identified j
by the NRC. is a violation of plant technical specifications. (Section U3.E8.1)
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Plant Support At Unit 2, although housekeeping and plant preservation activities are ongoing, the e
licensee offorts thus far have been good which reflect management's higher
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standards and expectations. Since June 1998, the number of catch containers for activo radiologicalleaks has been reduced from 80 to 3, and in 1997 the
contaminated areas have been reduced from 4784 square feet of recoverable area
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to 1048 square feet. Painting efforts, particularly in the turbine building and
auxillary feedwater pump rooms, have not only improved the plant's visual appearance but more importantly serves to preserve plant equipment. (Section
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Renort Deinita
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Summarv of Plant Status Unit 1 remained in an extended outage for the duration of the inspection period. The licensee has announced that there will be further reductions in restart activities at Unit 1 through the end of 1998. Activities associated with the implementation of the configuration management program (CMP) will be reduced to a level of effort to support completion and documentation of the work performed to date. The total number of Unit 1 personnel will be reduced to provided support for the ongoing restart efforts at Units 2 and 3. Currently, the licensee is reviewing the Unit 1 management organization to accommodate the reduction in staff Unit 1 personnel will focus their efforts on performing corrective and preventative maintenance in order to maintain the plant in a safe shutdown condition.
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U1.1 Onorations
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U101 Conduct of Operations 01.1 General Comments 171707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Control room panel walkdowns were performed to identify whether
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significant plant parameters and indications were at expected values for current plant conditions; whether any significant trends exist; or whethei the safety and risk significant systems including their support systems are appropriately aligned and operable. The inspectors also attended the licensee's plan of the day meetings, and other meetings as
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appropriate to obtalt) the overall status of the plant and of the licensee's activities that were planned or in progress. Noteworthy observations are detailed in the sections below.
01.2 Gas Turbine Genatator Fuel a.
insoection Scone (71707)
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The inspector evaluated the licensee's disposition of condition report (CR) M197 2525 which was initiated by the licensee on December 11,1997. This CR described that fuel oil for the emergency gas turbine generator (GTG) which has been delivered, accepted, stored, and used for several years, has been ASTM D 3399 K 1 Kerosine versus ASTM D 1655 Jet A 1 aviation fuel as required by the applicable purchase order, b.
Observations and Findinas The inspector discussed the CR with the system manager, who stated that he reviewed various documents related to the fuel requirements of the GTG, such as correspondence to the GTG manufacturer, General Elt.,tric (GE), technical manuals, and procurement records.
The system manager stated that based on the documents reviewed and conversations with GE, the kerosine that has been delivered, accepted, stored, and used for at least two years was one of the fuels recommended for use in the GTG. The system manager further stated that the availability determination (AD) which was generated as a result of the CR.
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supported continued reliance on the GTG to support necessary loads in the event of a loss of normal power as demonstrated by successful complet!on of monthly surveillances.
The inspector reviewed the reportability determination (RD) which was generated as a result of the CR. The RD not only reflected the statements made by the system manager, but c'so referenced documents provided by and discussions with GE, that supported the use of korosine as a fuel source for the GTG, The RD also indicated that kerosine would not degrade the performance of the GTG or the GTG itself. In addition, the RD indicated there was a direct comparison between ASTM D 1655 Jet A 1 aviation fuel and K 1 Kerosine.
The inspector reviewed several documents provided by the licensee and identified conflicting fuel specification requirements. Moreover, the documents indicated that the licensee historically relied upon one or more of the following documents to either perform specific tasks, such as receipt testing of GTG fuel or as the basis for engineering decisions performed under the work control process:
Amerada Hess Corporation Marketing Specification for K-1 Kerosine
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GE Publication gel 41047H
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GE Fuel Specification MID IDM 2500 9, Appendix A2: MID TD 0000-2
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GE Fuel Specification MID-S 0000-3
ASTM Spucification for Kerosine D 3699
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ASTM Specification for Aviation Turbine Fuels D-1655
Production Analytical Laboratory Sample Test Record
Operating Procedve C OP 600.5 Attachment 2, Aviation Fuel Sample Checklist
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Chemistry Procedure CP 807/2807/3807AAL, Revision 1, Diesel Fuel Oil and
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Aviation Turbine Fuel Sampling Procedure.
The inspector noted that chemistry procedure CP 807/2807/3807AAL, details the collection and sampling of fuel oil each time a fuel oil delivery for the gas turbine is made, specifically, the requirement for chemistry to verify the bill of lading matches the sample requested for kerosene.
Approximately eight days following the initiation of the CR, the inspectors discussed with the Unit 1 Director how future shipments of fuel for the GTG wou!d be processed, and if these future shipments, if they were korosine, would be accepted for subsequent storage and use. As a result, a memorandum was generated by Operations on December 24, 1997, circulated to all shift managers, and directed that GTG fuel would not be ordered until the Operations Manager was contacted, essentially preventing future shipments of K-1
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Kerosine.
On December 30,1997, the inspector was briefed by the Unit 1 Operations Manager
! :arding the status of activities in response to CR M197-2525. The Operations Manager detailed previously discussed items such as the generation of the CR, AD and OD, and the issuance of the operations memorandum. Also in attendance during this meeting was the Unit 1 Procurement Team Manager, who discussed new issues such as the closure of the
current purchase order with the GTG fuel supplier for aviation Jet A 1 Fuel on December
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24,1997, such that further requests for shipments would be prevented. in addition, the Procurement Manager stated that during the time period 1994 to 1995, procurement was removed from the receipt inspection process for the GTG fuel, and the chemistry department assumed responsibilities for receipt inspection of the GTG fuel when applicable.
The inspector was also briefed on two systems which use fuel that were idendfled to have technical requirements for the procurement and receipt inspection process: the diesel fire pump (M7 7) and the meteorological tower generator. Condition reports were generated for both of these systems as a direct result of the investigation performed under CR M1-97 2525. Subsequently, engineering technical support, was tasked with and assumed ownership of an unresolved corrective action: to determine the correct type of fuel to use in the GTG.
In a January 6,1998 letter to GE, engineering requested answers to questions regarding the following: (1) the suitability of K 1 Kerosine for use in the GTG; (2) which fuel specification the licensee should refer to in the future; (3) for reasons of availability, if K 1 kerosine was an acceptable fuel for future use; and (4) what ana,1yses and applicable test methods were required to be performed for the required fuel, c.
Conclusions Condition report M197 2525 was initiated by the licensee on December 11,1997. This condition report described that fuel oil for the emergency gas turbine generator which has been delivered. -~_pted, stored, and used for several years, has been ASTM D 3699 K 1 Kerosine verst.: ASTM D 1655 Jet A 1 aviation fuel as required by the applicable purchase order. The NRC determined that while successful monthly surveillances indicated the emergency gas turbine generator was capable of burning kerosine, the licensee's lack of timeliness in the Identification of the discrepancy between the purchase order fuel requirements and the acceptance, storage, and use of fuel oil, as well as the lack of timeliness in taking immediate or interim corrective actions ic considered a weakness. In addition, the conflicting fuel specifications that support various licensee procedures and processes, as well as the inability of the licensee to adequately determine the exact fuel ths.t is required for use in the gas turbine is considered unresolved. (URI 245/97 208-01)
U1.Il Malntenance
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U1 M1 Conduct of Maintenance M 1.1 Standbv Gas Treatment System (SBGT) Surveillance a.
Insosction Scoce (61726)
The inspector observed performance of the monthly operational check of the standby gas treatment system (SBGT) which was accomplished in accordance with SP 646.8, Section 4.2, "SBGT Train 'A' 15 Minute Operational Check."
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b.
Observations and Findinos The Unit Supervisor performed a pre brief with the operating crew and discussed the overall objectives and process for the surveillance, as well as associated precaution and limitations. The operation of the 'A' train of the SBGT system was accomplished by a unit ope'ator in accordance with approved procedures. However, while attempting to start the
'A' SBGT f an, HVE 5A, the operator recognized that the fan did not start when the control switch was placed in the " start" position. The oparator immediately recognized that the
'A' SBGT system was in " lockout" by observing the ""A" SBGT IN LOCKOUT" annunciator on panel 025 A 1, which was lit. After placing the 'A' SBGT system lockout swl'...)in
" normal," the operator successfully started the 'A' SBGT fan, and continued with the surveillance. Upon completion of the operational run, the acceptance criteria were considered satisf actory and the surveillance was completed, c.
Conclusions The inspector concluded that the licensee's performance of the standby gas treatment system (SBGT) surveillance was good. However, the lic.ensee failed to identify the effect the SBGT system status would have on the performance of the surveillance. Specifically, the p*e job brief should have addressed the SBGT system * lockout" status and the need to place the system in a condition tnat would allow successful completion of the surveillance using the approved procedures. In addition, notwithstanding the fact the SBGT system status was not addressed in the pre job brief, the operator should have recognized the need to place the SBOT system in " normal" to successfully start the applicable fan.
M1.2 Core Sorav system (CS) surveillance a.
insoection scone (61726)
The inspector observed performance of the quarterly operational test of the 'B' CS system and associated remote valve indication checks which were accomplished in accordance with SP 621.10B, "'B' Core Sprey System Operability Test," and SP 621.11B, "'B' Core Spray System Remote Valve Indication Check."
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Observations and Findinas The Unit Supervisor performed a pre brief with the operating crew and discussed the overall objectives and process for the surveillance, as well as associated precaution and limitations, in addition, a unit operator provided a more detailed discussion regard.ng the procedural requirements of the surveillance, the general sequence of events, and coordination of personnel to complete the surveillance. The operator also briefed the crew about the potential communication problem the crew might encounter while perforrning the remote valve indication portion of the test for valves in the torus, but indicated that the use of radios might prevent recurrence of this previously identified proble _
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The operability test of the 'B' CS pump was performed satisf actorily and the crew continued with performance of the remote valve indication checks. However, during the performance of the remote valve indication checks on valves in the torus, the operator in the torus had informed the inspector that communication could not be established with the control room. The crew continued testing on the remaining valves, and completed the checks on valves in the torus at the end of the procedure with the assistance of nn additional persco who conimunicated with the control room on behalf of the operator at the valve location, c.
Conclusions The inspector concluded that thu licensee's performance of the core spray system surveillance was good.
U1 NI4 Maintenance 3taff Knowledge and Performance M4.1 Manaaement Work Observation Trainina a.
Insoection Scoce (62707)
The inspectors reviewed a training initiative associated with a practical training " mock-up" used to evaluate and provide feedback to individuals who perform work observations. The purpose of the training was to reinforce the standards for work performance as management conducts work oMervations. The training mock up was staged in the Unit l'
turbine building in an equipment area that was previously retired in place, b.
Observat ons and Findinas i
Unit 1 line management and nuclear oversight developed a traidng mock-up that simulated an actual work area and demonstrated numerous examples of unacceptable work practices.
The mock up ircorporated over 100 deficiencies in the areas of housekeeping, tagging, automated wo:k orders, foreign material exclusion, radiological controls, industrial safety, and in'erpersonal communication or coaching. The deficiencies originated from a review of more than 1500 condition reports and pravious work observations with a particular emphasis on repetitive di crepancia. The mock up also included an individual playing the role of a worker to prompt an interact:on with the supervisor to facilitate the coaching i
aspect of the training, l
l Participants in the exercise were paired with individuals from different departments and had l
approximately 45 minutes to ident7y as many issues and problems a they could in that
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time. At the end of the allotted time, the mock-up facilitator performed a critique of the participant's performance during the work observation. The results of the critique were documented on a " Completion Record" and the individual was allowed to provide feedback and comments on the training. Successful completion of the exercise indicated that the supervisor had demonstrated an ability to evaluate a work activity that contained numerous deficiencies. At the end of the inspection period,78 Unit 1 managem3nt individuals had
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successfully participated in the mock up training. Additionally,12 individuals from other organizations have attended the training, including Unit 2 and 3 personnel.
Feedback from the participants regarding the mock up has been very favorable and indicates individual awareness of the problems with work activities has been raised. As a result, some supervis... have asked to bring their work groups through the mock up in an effort to raise their standards of performance, specifically by making them aware of the standarda they are being evaluated against.
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Conclusions Line nunagement and nuclear oversight worked on a collaborative effort to develop a practical training " mock up" that is being used to evaluate and provide feedback to management individuals who perform work observations. The mock up incorporates over 100 actual deficiencies that were identUled in condition reports and work observations.
This annovative training methodology is an excellent management tool for reinforcing higher standards for work performance in the p'. ant, and also provides an additional opportunity for participants to learn from one another. Feedback from the participants has been very favorable.
U1 M8 Miscellaneous Maintenance issues M8.1 (Closedi LER 50-245/96-53-00: Radiation Effluent Menitor Source Check Surveillances Not in Accordance with Technical Soecifications (Update - SIL ltem 101)
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jnsoection Scoce (927001 The inspector reviewed the licensee's findings and corrective actions associated.vith compliance with the Technical Specifications (TS) for the performance of a monthly source check for the radiation effluent monitors. The inspector reviewed the licensee's closure package for this Licensee Event Report (LER), which included associated adverse condition reports (ACRs), operability determinations, and copies of the revised and new procedures for performance of the monthly source checks of the monitors. The inspector also verified that the licensee met the reporting requirements of 10 CFR 50.73.
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Observations and Findinos On October 2,1996, the licensee identified that the TS requirements for the performance of monthly source check for the radiation effluent monitors had not been met. The discrepancy was identified during a review of the master surveillance test list. In addition, procedures to satisfy source check requirements were not present for three specific radiation monitors: steam jet air ejector off-gas, main stack noble gas, and service water effluent line radiation monitors. Adoitional assessments of effluent monitors determined that the liquid radwaste effluent radiation monitor was also affected, specifically that TS required a source check to be performed prior to each batch release. The failure to source
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check the Unit 1 main stack noble gas radiation monitor was also applicable to the TS of Units 2 and 3.
The cause of this event was that previous interpretations had held that since the monitors were indicating radiation while performing the TS required daily instrument cher:k, they
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were essentially responding to a radioactive source; therefore a qualitative at.sessment could be made based on this response, and thus satisfy the requirements of a source check. The instrument check was therefore believed to be adequate to satisfy the scurce check requirements. During review of the ACR,it was determined that sufficient documentation did not exist to support this method and did not meet the intent of a TS required source check when compared to industry standards.
At the time of the event, the 18 month TS surveillance had been performed for both the main stack noble gas and service water effluent line radiation monitors. As a result, the licensee took credit for the solid source calibration and maintained the monitors h an operable status. A historical review of the 18 month solid source calibration results indicated that none of the monitors had been discovered to be non responsive when exposed to the radioactive calibration sources.
The licensee has implemented corrective actions for the issue in that new procedures have been generates or existing procedures were revised to satisfy the TS required source check
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for all four of the affected radiation monitors. The following pmcedures properly incorporate the TS requirements for a monthly source check:
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CP809A Rev.18 * Liquid Waste Discharge" was revised to include steps to conduct o
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a source check prior to each discharge and was approved an December 19,1996.
- SP850 Rev. O, " Millstone Nuclear Power Station Unit 1 Stack Gas and Service Water Effluent Monitor Source Check was approved on March 27,1997.
- SP406EE Rev. O, " Air Ejector Off Gas isolation Radiation Monitor Source Checks" was approved on March 27,1997,
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ConclusiOD The inspector verified that the procedures were appropriately revised / developed and concluded that the licensee's corrective actions were adequate. This licensee-identified technical specifiution non-compliance 'a being treated as a Non-Cited Violation, consistent with Section Vll.G.1 of the NRC Enforcement Poliev. LER 50 254/96-53 is closed.
M8 2 (Closed) LER 50-245/96-63-00 and 96-63-01: Steam Tunnel Vent. Reactor Buildina y_ent and Refugl Floor Vent Radiation Monitors Downscale Trio Function inocerable I
(Updato - SIL ltem 101)
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a.
Insanction Scone 192700)
The inspector reviewed the licensee's findings and corrective actions associated with downscale trip functions for vent radiation monitors that did not trip as required by design.
The inspector reviewed the licensee's closure package for this LER, which included associated adverse condidon reports (ACRs), condition reports (CRs), operability and reportability determinations, root cause evaluations, and copies of the revised and new procedures f( e performance of monthly source checks of these monitors. The inspector also verified that the licensee met the reporting requirements of 10 CFR 50.73. This event was also reviewed and documented in NRC inspection report 50 245/96-09, section U 1. M 1.1.
b.
Observations and Findinas On November 26,1996, the licensee dentified during surveillance testing that the downscale trip functions for both steam tunnel vent radiation monitors did not trip as required by design. The downcate trip points were immediately adjusted and re-tested satisf actorily. The downscale trip function actuates when the detector signal falls below the low trip point and provides a f ailsafe action for failures such as loss of detector high voltage or signal. Subsequent failures of both steam tunnel vent downscale trips to function could have resulted in undetected failures of both monitors. It was detern:ned by the licensee that with the failure of the downscale trip feature, the steam tunnel vent radiation monitors remained capable of performing their intended safety function, isolating the ventilation system on an upscale trip signal, and were considered operable. Technical Specifications (TS) do not require a downscale trip nor specify a setpoint for the downscale trip. The cause of this event has been attributed to a procedural deficiency which required the adjustment of the monitor's downscale trip points to a value that was difficult to read and provided little margin to the signal failure point in the event of setpoint drif t.
As a result, all Unit 1 radiation monitor surveillance procedures were reviewed for similar procedural deficiencies. On March 11,1997, the results of this review determined similar procedural deficiencies for the reactor building exhaust duct and refuel floor high radiation monitors, which are TS required monitors, and the isolation condenser vent radiation monitors and other radiation monitors not required by TS. These deficiencies were reported to the NRC on April 9,1997, as a supplemental LER (96-063-01).
The licensee has implemented corrective actions for this issue. Functional test and calibration procedures for the above mentioned radiation monitors were changed to adjust the downscale trip point to a value rufficiently above the meter zero so that sufficient drift margin exists. For ertmple, " Steam Tunnel Ventilation Radiation Monitor Calibration for RIS 1705 36A" Revision 0, was revised to convert the values used for setting the trip setpoints from mRlhr, as read using visual interpolation of a logaritnmic scale on a local indicator, to mA as read utiliz!ng high accuracy test equipment.
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Conclusion The inspector verified that the procedures were appropriately revised and concluded that the licensec's corrective actions were adequate. The closure package associated with these LERs was comprehensive and thoroughly address the identified issues.1.ER 50-254/96 63 00 and 96-63-01 are closed.
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U1.lil Engineering U1 E7 Quality Assurance In Engineering Activities I
E7.1 (Closern Unresolved item (URl) 50 245/95 81-01: Trend Analvsls of NCRt and.
ACRs: Closed to eel 20129/ Notice of Violation letter dated December 10,1997, violation number ll.A.10 a.
Insoection Scone 192903)
The inspector rev!ewed the licensee's corrective actions regarding the f ailuro to trend NCRs and level *D" ACRs in accordance with the Quality Assurance Program for Millstone Units 1 and 3. Unresolved item (URI) 95-81 01 was generated from the Millstone Safety Assessment and Independent Oversight Team Inspection that occurred on all three Milistone units in September and October of 1995, b.
Observations and Findinos The licensee's quality assurance program requires that a trend analysis of nonconformances documenting program / procedural problems be performed, and the trend analysis reports identifying program / procedural problems be periodically reported to upper management by the organization responsible for controlling the problem reporting document. URI 50 245/95-81 01 concerned the fact that nonconformance reports (NCRs)
initiated by the quality assurance (QA) department and level "D" adverse condition reports (ACRs) were not included in tho trend report, nor was there any requirement to trend these items. Based on these findings, the lack of trending NCRs and verifying the effectiveness and adequacy of the ACR database by the QA department was considered an unresolved item.
Subsequent to the NRC inspection, NOOP 4.09, " Planning, Scheduling, and Administration of Ouality Surveillance Activities," was revised to include quarterly NCR, level "D" ACRs, and the " effectiveness of corrective actions" reviews. These reviews were performed by the nuclear oversight department, formerly the QA department. Further change occurred when NGP 3.05, "Nonconformance Reviews," was revised and included a requirement to trend NCRs in accordance with RP-4, " Corrective Action Program," and also required a Condition Report (CR), formerly known as an ACR, to be written for every NCR. The revision of NGP 3.05 and the creation of a unitized corrective action department shifted the responsibility of trending NCRs and CRs from nuclear oversight to each unit, but the
" effectiveness of corrective action" reviews remained the responsibility of the nuclear oversight departmen _
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The inspector reviewed the following documents to verify the adequacy of NCR and ACR trending by the licensee since the issuance of URI 95 8101:
Surveillance MP2 P 97 014, *NCR Trends, First Quarter, 1997," 4/30/97
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OAS Audit Report, " Corrective Action Adverse Condition Reports (ACRs),"
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6/19/97 Millstone Unit 1 Second Quarter CorrectNe Action Program Trend Report,8/1/97
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Millstone Unit 3 Third Quarter Corrective Action Program Trend Report, 10/30/97
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Millstone Unit 3 Memo, MP3 CAD 97 069, *NCR Trending," 12/15/97
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Millstone Unit 1 Operational Readiness Plan Performance Indicators, 12/19/97
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c.
Conclusions The lack of trending NCRs and verifying the effectiveness and adequacy of the ACR database by the OA department, unresolved item (URI) 95 8101, was generaMd from the Millstone Safety Assessment and Indepent ent Oversight Team inspection that occurred on all three Millstone units in September and October of 1995, While all units now issue quarterly Corrective Action Program t,nd reports, Unit 3 also issues quarterly NCR trend reports. However, Unit 1 does provide "NCR Closure" and "Open NCR Status Breakdown" Performance Indicators in the Operational Readir. ass Plan, which are provided for upper management review. In addition, the trending of NCRs is bounded by the requirement in NGP 3.05 to generate CRs for every NCR, as well as the tracking / trending functions performed in accordance with RP 4 for all CRs. While the link between the requirement to trend NCRs and the Unit 1 CR process Is not well delined,it appears to adequately address URI 50 245/95 8101 and this item is considered closed to Eci 20129/ Notice of Violation letter dated December 10,1997, violation number ll.A.10, coiteerning the NCR program.
However, eel 20129, remains open pending NRC review of the licensee's response to the Notice of Violation.
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80Dort Detalla Summarv of Unit 2 Status Unit 2 entered the inspection period with the core off loaded. The ur.it was initially shut down on February 20,1996, to address containment sump screen concerns and has
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remained shut down to address the problems outlined in the Restart Assessment Plan and an NRC Demand for Information 110 CFR 50.54(f)] letter requiring on assertion by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Report.
U2.1 OReta1Lona U201 Conduct of Operr.tlons 01.1 kral Comments (717071 Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations, particularly with respect to shutdown risk management controls. Where appropriate, interviews were conducted with licensed operators and other support personnel to assess the level of control and detail of knowledge being implemented with regard to observed operational evolutions. Overall operator performance during the inspection period continued to be very good. Changes in plant conditionc to support maintenance activities were well controlled and event free.
On November 26,1997, while performing a routine strainer maintenance procedure, a piece of debris was discovered in one side of the duplex inlet strainer for the service water system supply to the "B" emergency diesel generator (EDG) heat exchangers. The debris consisted of one approximately 6 inch by 12 inch piece of plasticized polyvinyl chloride (PVC) piping liner material, and was found in the strainer basket that had been in service.
The PVC liner, which is manuf actured by the Arbonite Company and carries the trade name
"Arbosol," is used to protect the carbon steel pipint, internals from exposure to seawater.
Since Arbosolis used in various locations in both service water trains, both trains were declared inoperable pending licensee inspectinn of the service water piping I;ning. The licensee reported this condition to the NRC in accordance with 10 CFR 50.72. The Arbonite lined piping was installed in five phases from 1988 to 1995 to replace epoxy lined piping. This is the first instance of a piece of PVC liner being found in either a strainer or a heat exchanger tube shoot. The licenseo completed their internalinspections of the "A" service water piping (which had been previously cross connected to cool the "B" EDG) and did not locate the origin of the piece of PVC liner. Licensee Event Report 336/97 37, which discusses this event, will be reviewed in a future NRC inspection report, i
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U2.llJlaintenance U2 M1 Conduct of Maintenance M 1.1 Maintenance Observationg The inspectors ooserved and reviewed selected portions of preventive and corrective maintenance and surveillance tests and reviewed test data to verify: adherence to regulations, and administrative control procedures, and technical specification limiting conditions for operation; proper removal and restoration of equipment; appropriate review and resolution of test deficiencies; appropriate maintenance procedures in use; adherence to codes and standards; proper QA/OC involvement; proper use of bypass jumpers and safety tags; adequate personnel protection; and, appropriate equipment alignment and retest. The inspectors reviewed portions of work activities associated with: (1) Change Low Air Flow Sensor Retrofit for inverter #1; (2) "A" Intake Bay Irispection, ar.d; (3)
Inspection of Service Water Piping Liner. Overall, the above maintenance and surveillance activities observed were performed adequately. A discussion of the Unit 2 program to inspect various installed plant instrumentation to insure shipping material had been removed is contained in Unit 3 section M2.2 of this report. Additional observations are discussed below.
M1.2 Emeroencv Diesel Generator Oversaged Trio Test (61726)
The inspector observed operations and maintenance department personnel setup the mechanical governor for the "A" emergency diesel generator using surveillance procedure SP 2661, " Emergency DG Overspeed Trip Test." During performance of the governor setup procedure, the operations and maintenance personnel questioned the sequence and correctness of the procedure steps. This instance was the first performance of procedure SP 2661 since its revision to integrate separate operations and maintenance procedures for the diesel generator overspeed trip test into a single procedure. The involved personnel suspended performance of this critical path surveillance test to implement a procedure change to resolve the questions. The inspector reviewed the implemented change and determined that the change constituted an enhancement to the procedure rather than a change necessary to make the procedure technically adequate. The inspector concluded that maintenance and operations personnel demonstrated good technical knowledge and high standards with regard to procedura! compliance.
l M1.3 Containment Particulate Process Radiation Monitor Functional Test l
a.
insoection Scoce (61726)
The inspector reviewed surveillance procedure SP 2404 AK 1, " Containment Particulate Process Radiation Monitor RM8123A Functional Test," and observed performance of the surveillance test. The inspection activities included discussions with instrumentation and l
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control (l&C) technicians and review of relevant technical specifications and final safety analysis report sections.
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Chantations and Findinas The inspector reviewed procedure SP 2404 AK1 against the requirements of Technical Specifications 4.3.2.1.1,4.3.2.1.4, and 4.3.3.1. The test procedure specified insertion of a test current into the radiation monitor to verify that the associated engineered safety features actuation system (ESFAS) bistable trip and control room alarms actuated at accepteble values. In the event of elevated containment particulate radiation levels, the i
ESFAS bistable trip provides the actuation signal for automatic containment purge valve closure to isolate a potential release path, and the alarms alert the control room operators
to the condition.
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The inspector determined that periodic testing of automatic containment purge valve
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Isolation by the ESFAS bistable trip was required by Technical Specification 4.9.4.b and
surveillance procedure SP 2605H, " Containment Isolation Valve Operability Test -
Shutdown," specified steps to perform that testing.
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For the duration of this reporting period, the containment particulate process radiation
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monitor RM8123A l.as been inoperabte, and the licensee maintained some of its supporting equipment in a non-functional state. The inspector found that appropriate compensatory measures were in place.
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During the initial attempt to perform the procedure, the l&C technicians identified that l
some steps of procedure SP 2404 AK1 were inappropriate or confusing because of the state of the supporting equipment. The l&C technicians elected to exit the procedure and complete the procedure change process before continuing with the procedure, j
Af ter the procedure change was implemented, the inspector observed completion of the surveillance test. Equipment used in the test was within its current calibration cycle.
l The inspector identli;ed no performance discrepancies, c.
Conclusions
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The surveillance procedure adequately li va nented the required testing of the containment particulate radiation monitx. The I&C tunnicians demonstrated good sensitivity to compliance with surveillance procedures by pursuing a procedure change to resolve inconsistencies between SP 2404-AK1 and plant conditions, and the technician's performance was good during the performance of the surveillance test.
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U2 M3 Maintenance Procedures and Documentatl<-
M3.1 Wide Ranae Nuclear instrument Drawer Calib.at a.
insoection Scone (81726)
The inspector reviewed selected portions Revision 6, Change 7, to procedure SP 24171,
" Wide Range Channel Drawer Calibration," to evaluate the procedure quality and adequacy.
b.
Observations and Findings When a neutron enters a wide range nuclear instrument (NI) detector, the detector provides an output signalin the form of a disciete electrical pulse. This signalis fed to the wide rango Ni drawer circuitry which provides an indication of reactor power level based on the rate that these electrical pulses are received. Section 4.8 of procedure SP 24171, which provides instructions to calibrate the count rate indicator, specifies that a pulse generator (NMC PG 81) be installed into a test connection (J6) to provide a test signal into the wide range nuclear instrument (NI) drawer to simulate the signal provided by the wide range NI detectors. After setting the pulse generator to provide one electrical pulse each second, the reactor power indication on the front of the wide range NI drawer is adjusted to read one count per second.
s The inspector noted that procedure SP 24171, Step 4.8.12, specifies adjusting the pulse generator to provide one electrical pulse per second with an " output level as necessary."
The pulse generator has an adjustment knob that varies the output level from 0 to 10 Vdc.
However, the normal input provided by wide range NI detectors and pre-amplifier into the wide range NI drawer is only 0.02 to 0.2 Vdc. The wide range NI drawer has a pulse
- height discriminator to filter out electrical pulses less than 0.046 Vdc so a test signal slightly greater than this is all that should be necessary tn adjust the count rate indication.
The inspector was concerned whether the high test voltoge could damage the wide range NI drawer or if the calibration could be adversely affected. To evaluate how the licensee had historically performed this calibration, the inspector reviewed Revision 5, Change 2, of procedure SP 24171, which specified adjusting the pulse generator output level for a
" maximum signal." It should be noted that the pulse generator output level knob does not have a scale or markings to indicate the output level. Using an oscilloscope, the licensee
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confirmed the pulse generator output level could be adjusted from 0 to 10 Vdc.
The inspector discussed this concern with the licensee who agreed that the procedure SP 24171 should be changed to specify a test voltage in the range that the drawer would normally receive. The licensee stated that a 10 Vdc test signal from the pulse generator would not cause any physical damage to the drawer. The licensee also stated that a high test voltage should not affect the calibration of the wide ronge drawer because the indication is being adjusted based on the frequency (one count per second) of the test pulse, not the amplitude (voltage).
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Conc!usion Procedure 24171 allows the test voltage from the pulse generator to be much : gner than the wide range NI drawer would normally receive. This concern remalns unresolved pending: (1) NRC review of the change to procedure 24171 and (2) NRC review of the surveillance test results using the revised procedure to verify proper operation and sensitivity of the wide range Ni drawer; and 3) confirmation of the engineering basis for the
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test parameters used to show that the high test voltage did not adversely affect past
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calibrations or result in equipment damn.ge. (URI 336/97 208 02)
U2.lli Ennineering U2 E1 Conduct of Engineering E1.1 Eotential Seismic Intera:: tion with Safetv Related Eauloment in the Control Room
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a.
Insoection Scone (717071 On December 22,1997, the inspector walked down equipment located in the control room to evaluate the potential for interaction between temporary equipment and safety related equipment. The inspection activity included document reviews and interviews with operations department and design engineering personnel, b.
Observations and Findings On a routine control room tour, t -inspector noted that unsecured pieces of equipment (e.g., tall cabinets and rolling carts) were located near safety related equipment (e.g.,
control pr.nels and engineered safety features actuation system cabinets). The inspector reviewed Millstone station administrative procedure OA 8, " Ownership, Maintenance, and Housekeeping of Site Buildings, Facilities, and Equipment," Section 1.9, "P.equirements for
Restraining Temporary Equipment," which states that equipment that has the potential to move during a seismic event and cause damage to safety related equipment must be i
restrained. Attachment 3 to procedure OA 8 provides specific criteria for identifying potential areas for interaction and acceptable restraint methods. For box shaped items l
with height greater than base dimensions, such as filing cabinets, procedure OA 8 requires l
restraint if safety related equipment is located within a circular area around the item with a
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radius not less than the height of the item plus 6 inches. For items on wheels, such as rolling carts, procedure OA 8 requires restraint if saic'v related equipment is located in a clear, straight line-of travel from the item.
During control roorn tours, the inspector observed 8 unrestrained filing cabinets approximately 60 inches tall and 29 inches deep located within 60 inches of safety-related electrical cabinets (including engineered safety features actuation system cabinets) and unrestrained items on wheels (a copier and a book cart, both with wheel locks disengaged)
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with a clear, straight line of travel to safety related electrical cabinets (including the reactor protection system cabinets). The inspector discussed the discrepancies between procedure OA 8 restraint requirements and observed conditions in the control room with design
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engineering personnel, in response, design engineering personnelInitiated condition report M2 98-0026, which documented that severalitems in the control room were not in compliance with procedure OA 8 instructions to prevent potential seismic interaction.
The inspector evaluated the rncchanisms the licensee uses to control, on an ongoing basis, the restraint of temporary equipment introduced to or moved within the control room.
Procedure OA 8 assigns housekeeping responsibilities for the Unit 2 control room to the Unit 2 Operations Department. Design engineering and operations department personnel stated that the unrestralned equipment had been evaluateJ as acceptable under a discontinued program with different acceptance criteria. However, the Operations Manager informed the inspector that the records of that evaluation were not available. The Operations Manager also stated that the operations staff considered procedure OA 8 principally applicable to maintenance activities.
The licensee took interim corrective action by reviewing procedure OA 8 with the iesponcible members of the operations staff, removing the filing cabinets from the control room, locking the wheels of the copler, and relocating the book cart and locking its wheels.
Placement of unrestrained items near safety related equipment is a safety concern because of the potential for harsh impacts with safety related electrical cabinets to disable the safety functions of those cabinets or cause inadvertent actuation of engineered safety features systems. Section 4.5 of the Seismic Qualification Utility Group's " Generic Implementation Procedure (GIP) for Seismic Verification of Nuclear Plant Equipment," notes that special attention should be given to potential seismic interaction with electrical cabinets containing relays, such as the engineered safety features actuation system cabinets.
c.
Conclusions Appendix D to the NUQAP Topical Report states that the NUQAP is committed to utilize the guidance of Regulatory Guide (RG) 1.39, " Housekeeping Requirements for Water-Cooled Nuclear Power Plants." Procedure OA 8, the licensee's implementing procedure for RG 1.39, specifies criteria for restraint of temporary equipment in safety related areas. The failure of the licensee to properly restrain temporary equipment in the Unit 2 control room, such as the filing cabinets, the copier, and the book cart described above, is considered a violation. (VIO 50 336/97 208-03)
U2 E8 Miscellaneous Engineering issues E8.1 (Uodate) Eels 50-336/96-201-42 & 43: Material. Eauioment. and Parts List Proaram (Undate - Unit 2 Slanificant items List No.181 a,
lassction Scone 193903)
The overan site Material, Equipment, and Parts Lists (MEPL) program was reviewed in NRC Inspection Report 97-202. Comments and discussion were provided on issues specific to each unit. This se:: tion provides an overview and update on the specific aspects of the
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MEPL program for Unit 2. One of the main purposes of the MEPL program is to evaluate parts and components to determine their proper classification '.d safety function, b.
Observationetend Findinas Unit 2 has approximately 60,000 total components in the plant, of which about 12,000 are safety related. Each component may have multiple constituent parts that are listed on a Bill of Motorials (BOM) for that component. As part of the Performance Enhancement Program (PEP) in the early 1990's, the licensee reviewed the quality classification of about 28,000 components. In late 1994, the MEPL program was utilized to downgrade 998 components from safety related (Category 1) to non safety re.ated. It was later determined that a number of these downgrades were not correct. Thus,in 1995 and 1996 all of the downgraded components were upgraded back to safety related. During the time period that the components were improperly classified, work was performed on them as non-safety related components, creating the possibility that substandard parts may have been installed. To address this concern, the licensee reviewed each of the 400 to 500 automated work orders (AWOs) that had been performed during this time period on these components to determine if non safety related replacement parts had been installed. Seven instances were identified that required that nonconformance reports (NCRs) to be issued and various corrective actions to be taken. As of the end of this inspection report period, not all of the NCRs had been fully dispositioned. During the fall and early winter of 1997 the licensee addressed these seven NCRs as follows: five were dispositioned "use as is" and two were designated as " rework" required. Alllicensee actions are not yet complete and some review of these by the NRC is continuing.
To further address the various concerns associated with classification of components and the MEPL program, Unit 2 performed a MEPL re-review of all systems and all safety related components. These reviews and evaluations are being done at the component level (versus the BOM part level.) At the end of this inspection period, this review process was about 90% complete.
Safety-related components may have constituent parts that are safety-rolated and other parts that are non safety-related. At Unit 2, a specific MEPL evaluation has not been performed for all parts on the BOM of each safety-related component to define the classification of these parts and therefore, the classification for these parts is often listed as * Undetermined." For parts classified as " Undetermined,"it has been an expectation that either a safety-related part be installed or a MEPL evaluation should be performed to classify the part as "Non-Safety Related." However, the licensee has identified instances where parts designated as " Undetermined" had non-safety related parts installed. In addition, many of these parts that do not have a specific MEPL evaluation are also designated as "Non-Safety Related" rather than " Undetermined" and is it unclear how or i
when these components received this designation. The licensee has identified instances where parts design =ted as "Non-Safety Related" that did not have a supporting MEPL evaluation had work performed with non-safety-related parts installed.
To address this problem associated with " Undermined" and "Non-Safety Related" parts, the licensee is ensuring a MEPL evaluation exists for all new parts that are being installed l
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during the current outage. This practice is adequate to address this problem on an ongoing basis. However, at the end of the inspection period, the licensee has not provided a justification regarding the extent that work history reviews must be performed to identify other past examples of non safety related parts being inappropriately installed.
The MEPL evaluations performed during the current outage have resulted in a number of instances whereby " Undermined" or "Non Safety Related" designated parts or components have been upgraded to " Safety Related." In these cases Specification 944, " Standard Specification for Material, Equipment, and Parts Lists for In Service Nuclear Generation Facilities (MEPL Program)," Figure 7.7, requires that a non conformance report (NCR) be issued. To date there have been 91 such NCRs issued, some of which address multiple parts or components. The inspector reviewed a sample of these NCRs and noted two problems with the resolutions of "use as is" on the NCRs. Specifically, the NCRs did not provide any basis for the continued use of previously non safety related materialin a safety related application (e.g., NCR 297 367 and NCR 297 449). This material was most likely installed since original construction, and the NCR did not provide any examination of the original specification to confirm that the material could perform its newly defined safety related functions. Also, when the work history review identified that non safety-related work was performed on these components or parts, a component or part specific basis was not provided for the "use as is" resolution (e.g., NCR 297 367 and NCR 297-450). Although Specification 944 requires an NCR to be generated in these cases,it does not provide any guidance on how to resolve the NCR: as a result of this lack of guidance, Unit 2 resolutions did not contain sufficient information to justify their closure as noted above. The Engineering Assurance Group also performed a self assessment in this area and, subsequent to the inspector's observations, issued Condition Report M2 97 2816 to address this issue.
Currently, the licensee is developing an Engineering Department Instruction (EDI) to provide guidance for the disposition of NCRs generated when the MEPL program upgrades the OA classification of a component or part. NCRs issued during this outage will then be reviewed using that EDI. As a result of this review, necessary actions will then be taken, which may include replacement of parts with safety-related parts, repair / rework, or further evaluations by design engineering or procurement engineering (e.g., commercial grade dedication). When those actions are complete, the licensee will evaluate the overall results and determine if any additional activities are rieeded to address the general question of non-safety-related parts being used in safety related components.
c.
Conclusions The licensee has a significant number of parts, with no MEPL evaluations, in the BOM of safety-related components that are designated as either " Undetermined" (U) or "Non-Safety Related" (N). When MEPL evaluations of some of these parts reclassified the part as safety-related, subsequent work history reviews have shown that non safety related replacement parts had been installed. The licensee is still evaluating this area and developing corrective actions to address the issue of past work controls associated with these " Undermined" and "Non Safety Related" parts, i
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Further, for parts or components that have been upgraded to " Safety Related", Unit 2 appropriately issued NCRa. However, resolution of the NCRs did not contain sufficient information to justify their closure, as noted above.
In addition to these two skalfic aspects above, further review remains on the Unit 2 MEPL SIL, including: resolution of the site wide MEPL issues noted in NRC Inspection Report 97-202, resolution of the MEPL aspects of consumable controls noted in NRC Inspection Report 97 203, review of the Unit 2 specific aspects of Escalated Enforcement items (Eels)
50 330/96 201 42 & 43, and a sampling implementation review of Unit 2 MEPL evaluations completed during the current outage. Therefore, Eels 50 336/96 201-42 & 43 remain open.
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Beoort Detalla Summarv of Unit 3 Statua Unit 3 remained in cold shutdown (Mode 5) status throughout this inspection period, as the licensee continued to implement recovery activities. The Independent Corrective Action Verification Program (ICAVP) inspection activities, conducted separately by both the NRC Special Projects Of fice and Sargent and Lundy, have also continued in an effort to assess the adequacy of the licensee's configuration management program (CMP), as well as evaluate the design and operational readiness status of selected safety systems. As detailed in the following report sections, the licensee has submitted completed corrective action packages for severalissues being tracked on the Unit 3 Significant items List (SIL)
included as part of the NRC Restart Assessment Plan (RAP) for Millstone Station. As of the end of this inspection period,38 of the total 86 SIL nems for Unit 3 have been closed; 30 additional SIL items have been partially inspected and updated; and the licensee continues to work on corrective action completion and submittal of the packages supporting the remaining SIL ltems.
During the period from December 1 -17,1997, an NRC team conducted an on site inspection of the ICAVP Tier 2 accident mitigation systems at Unit 3. This inspection team had completed a review of the licensee's change process controls (i.e., ICAVP Tier 3 review) in November,1997. A publicly observable management exit meeting for NRC discussion of the Tier 2 and 3 inspection findings with the licensee was conducted on January 28,1998. Another NRC team inspection of the licensee's Employee Concerns Program and Safety Conscious Work Ervironment was conducted on site from December 8-12,1997. This inspectinn was scheduled to continue in January,1998 with a publicly observable exit meeting to discuss the inspection results with licensee management planned for January 22,1998.
With the departure of Mr. N. Carns, effective December 1,1997, Mr. B. Kenyon, the Northeast Nuclear President and Chief Executive Officer, also assumed the duties of Senior Vice President and Chief Nuclear Officer in an acting capacity. The new NU management organization for Millstone Unit 3, with Mr. J. McElwain as the Acting Recovery Officer reporting to Mr. M. Brothers in the new position of Vice President of Operations remained in effect over the course of this inspection period.
l On December 10,1997, the NRC issued a notice of violation and proposed imposition of I
civil penalties against Millstone Station. Of the 34 separate inspection issues raised as examples of violations of regulatory requirements in Unit 3, all of the technical concerns
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have been documented and are being tracked in the Unit 3 SIL for consideration in restart
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deliberations by the NRC staff as part of the Millstone Station RAP. Two of the escalated enforcement items from this civil penalty package were inspected and closed, as documented in some of the following sections, during this report period.
As documented in inspection report 50-423/07 207, the NRC conducted an inspection review of the Unit 3 list of items to be completed after restart (i.e., the deferred items list),
submitted by the licensee pursuant to 10 CFR 50.54(f). The licensee was scheduled to i
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provide an update to this information during this inspection period, but by letter dated December 18,1997 Informed the NRC that the next update to the requested 10 CFR 50.54(f) lists would not be available until January,1998. Upon receipt of the new deferred items list for Unit 3, the NRC projects re inspection of this area in February,1998, i
U3.1 Onorations U3 01 Conduct of Operations 01.1 General Comments (71707)
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The inspector conducted frequent reviews of ongoing plant operations, in general, the
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conduct of operations was professional and safety conscious with an appropriate shift supervisor focus on shutdown risk. During tours of the control room, the inspector discussed any observed alarms or parameter trends with the operators and verified that
they were aware of any lit alarms or recorder trends and the reasons for them.
01.2 Followuo of Comoonent/ System Ooerability and Events (92901)
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The Inspector routinely observed plan of the day meetings, monitored selected maintenance planning meetings, and witnessed operations shif t turn-overs and certain plant evolution
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briefings. Specific inspection follow up activities were conducted when questions of safety related component or system operability were raised, Tec'inical Specification (TS)
l compliance or adequacy concerns were identif!ed. Where appropriate, the inspector reviewed Plant Operation Review Committee (PORC) approved operability determinations, temporary modifications, and several condition reports (CRs) addressing certain component deficiencies.
Specifically, the inspector spot checked operational activities and examined licensee documentation related to the fellowing issues:
o residual heat removal (RH A) flow control valve inoperability due to postulated
" weak link" analysis concerns l
l need for addit;snal TS controls or additional system analysis to credit the e
'ressurizer power operated relief valves for adequate operator and plant t
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response to a postulated inadvertent scfety injection event i
e acequacy uf certain quench spray system (OSS) air operated valves to serve l
as isolation boundary valves to preclude unanalyzed leakage from the l
refueling water storage tank
work control problems involving a service water (SW) pump overhaul and flow balanco activity l
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action plan implementation to evaluate and clean those heat exchangers e
adversely affected by sea grass intrusion into the SWP system, resulting from winter storm conditions impact of the Unit 3 National Pollutlon Discharge Elimination System (NPDES)
e permit upon the functionality of the SWF backwash strainers and resultant iteration of the SWP pumps Additionally, the inspector discussed with licensee operations and technical support personnel the applicability of some event reports from other nuclear plants of a similar design to Millstone Unit 3. Operability issues affecting component failure analysis for the contro! room ventilation system and the availability of the charging pumps to provide emergency core cooling flow were reviewed and determined to not be applicable to the Unit 3 design.
Overall, the inspector ider..fied no unresolved safety concerns with respect to operability issues for the current status (Mode 5) of the unit. The licensee has issued CRs, where appropriate, to evaluate and track the corrective actions necessary for proper resolution of the identified deficiencies or system restoration activities. Nuclear Oversight involvement in monitoring the above field activities, documenting adverse conditions in CRs, and verifying the adequacy of corrective measures was evident.
However, a number cf operational procedures may still require revision as a result of CR dispositions, the approval of pending licenss amendment requests, and continuing CMP review activities, implementing the needed changes, in addition to familiarizing the plant operators with the new requirements, appoar to be priorities that merit continued management attention.
U3 04 Operator Knowledge and Performance 04.1 (Closed) Licensee Event Reoort. LER 97-004: Lack of Verbat;m Comoliance with Technical Soecification Surveillance Reauirements for Molded Case Circuit Breakers (Update - SIL ltem 70)
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insoection Scooe (92700)
l LER 97-004-00 identified the concern regarding surveillance testing of 480V molded case circuit breakers (MCCBs) being performed in a manner not in verbatim compliance with the Technical Specifications (TS).
ACR MS-97-0136 documented the failure to comply with TS 4.8.4.1.a.2 which required
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additional two-pole combination testing of molded case circuit breakers whenever a failure
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of the single-pole instantaneous test occurred.
The inspector revie.ved the licensee's corrective actions to add ess the above-mentioned specific concerns and the mr 9 generic implications of verbatim compliance with Technical Specifications.
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Observations and Findinas l
TS 4.8.4.1.a.2 requires additional two-pole combination testing of 480V MCCBs whenever I
a failure of the single-pole instantaneous test occurs. ACR M3 97 0136 documented the licensee's practice of replacing an MCCB rather than performing additional two-pole combination testing following failure of the single-pole test. This practice did not suppon
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TS verbatim compliance. The lack of verbatim compliance was due to a misconception that performing surveillances under conditions "more conservative than" or " meeting the intent of" a specific TS requirement was acceptable for verbatim compliance. A cause of this lack of understanding was that management expectations and guidance regarding literal compliance with TS were neither clear nor adequately communicated throughout the organizs.lon.
NU memorandum MP3 A-97-042, March 20,1997, was issued to communicate Unit 3 management expectations on verbatim compliance with TS. Additionally, revisions to the MCCB surveillance procedure SP3'/12T, " Containment Penetration Overcurrent Device Surveillance Testing for Load Center, MCC, and Molded Case Breakers," have been made to ensure verbatim compliance with TS. The inspector noted that Revision 6 of surveillance procedure SP3712T included the instruction (Section 4.2.5) to perform two-pole testing following a single-pole test failure, and the additional 10% sample test requirements for each type of circuit breaker found to be inoperable. Surveillance data from previously performed surveillances on MCCBs per AWO M3-9513019 were reviewed, and no single-pole test failures were observed. Thus, no additional required testing of the sampled MCCBs were required. The inspector considered these corrective actions to address the TS compliance of MCCB surveillance testing activities acceptable.
Regarding the generic issue of verbatim compliance with TS, an action requirement, AR 9700938-08 was issued for the review of all maintenance (mechanical / electrical)
surveillance procedures to determine their verbatim compliance with TS. NU memorandum NL 97-049, February 26,1997, provided a list of TS surveillar'ce requirements which require an expansion of the test sample following a failure, and further requested department managers to review applicable procedures to ensure verbatim compliance with TS requirements. Condition Report CR M3 97-1641 identified incompleteness in the NL 97-049 listing of condition-based surveillances based on responses from the Operations, Maintenance, and Technical Support Departments. The departmental reviews provided a more complete list of condition-based surveillances and surveillance procedures with appropriate " triggers" to ensure condition-based surveillances would be performed and condition-based reports would be initiated (Reference memoranda MP3-O-1018, MS3-97-8, MS3 97-13, MP3-TS-97-132, MP3-TS-137, and MP3-TS-97-152). Several maintenance and surveillance procedures were revised to trigger the conditionai surveillance requirements after maintenance was perforrled. These procedures were: MP3718AA (Rev.
6), MP3718AB (Rev. 3), MP3766AB (Rev. 4), MP3766AH (Rev. 2), MP3771 AA (Rev 5),
MP3704048 (Rev. 3), SP3451N22 (Rev. 3), and 9"3441D02 (Rev. 8). The inspector identified no concerns with the revisions in th a nedures.
Another AR 96031948-07 was initiated for the -
aw of TS and implementing procedures to ensure that LCOs and Surveillance Requirements could be followed on the basis of intent
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and verbatim interpretation, Non-surveillance maintenance procedures which met TS surveillance requirements were converted into surveillance procedures (Reference AR 9700938-12). For example, maintenance procedures MP3782AA, MP3782CA, and MP3784AA were converted to surveillarce procedures SP3712TA, SP3712TB, and SP3712TC, respectively. Additionally, general operating procedure OP3273, " Control of Technical Requirements - Supplementary Technical Specifications," was revised to reflect the requirements for meeting both the intent and verbatim compliance with TS. The inspector considered these corrective actions taken to address the generic issue of verbatim compliance with TS to bo reasonable.
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Conclusions Licensee corrective actions to address the specific and generic concerns of verbatim compliance with TS were determined to be acceptable. The revisions to the MCCB surveillance p ocedures were acceptable to ensure verbatim compliance with TS. All of the corrective measures taken to address the generic issue of TS verbatim compliance were considered to be reasonable. Since it appears that the licensee has taken a comprehensive approach to address the issues in this LER related te verbatim compliance with TS, LER 97-004-00 is considered closeo Based upon the above corrective actions, this licensee identified and corrected violation of the Technical Specifications is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. SIL ltem 70 is hereby updated.
U3 07 Quality Assurance in Operations 07.1 Ooerational Oversicht Procram Activities During this inspection, the inspector continued to monitor and evaluate the programmatic activities in progress by Nuclear Oversight in assessing the readiness of Unit 3 plant and staff for startup and sustained power operation. The inspector reviewed Oversight activities that primarily focused on operational or configuration management program (CMP) performance. In the conduct of this review, the following documents weia examined:
Nuclear Oversight Restart Verification Plan (bi-weekly status windows)
Control of Overtime evaluations (e.g., surveillance MP3-P 97-136)
Assessment of the Millstone Unit 3 Reactor Coolant System Loop Fill, Sweep and
Vent Evolution Minutes of the NU Nuclear Safety Assessment Board (NSAB) Meeting 97-19,
December 1 and 2,1997 Unit 3 CMP Dee!an Deficiency Reports (DDRs) Review provided in response to a
NSAB request fer a DDR assessment t
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Nuclear Oversight Monthly Report - December 1997
The inspector noted that the licensee management decision in December,1997 to delay the NRC Inspection Procedure (IP) 40500 inspection that was originally scheduled to be conducted in early January,1998, was based, in part, on the Nuclear Oversight assessments indicating that all program areas may not have been ready for review.
Additionally, Nuclesc Oversight was found to have dedicated significant resources to the assessment of work planning and control, work performance, backlog reduction, and the conduct of operations in the control room. Whiie such effectiveness reviews identified some performance successes, several challenges in the CMP / work control areas were identified te persist. The Nuclear Oversight organization als^ expressed a concern regarding tne transition from an extended outage to an operating plant status. The inspector noted that the licensee approved in December,1997 certain operating procedures intended for use as pan of the Startup and Power Ascension Plan for transition from the current outage conditions.
The inspector idendfied an active and performance-based Nuclear Oversight organization that appeared to be thoroughly Iraolved in the assessment efforts to verify readiness of the plant, programs, and line personnel for unit restart. The i;npact of these Oversight efforts on overall performance will tse further inspected during the IP 40500 and subsequent
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operational readiness and corrective action team inspections planned by the NRC.
07.2 Review of NUREG-0737. TMI Action Plan Reauirements (Update - SIL ltem 38)
As documented in inspection report 50-423/07 207, an NRC inspection was initiated to review the current status of certain NUREG-0737, TMI Action Plan Requirements. That review continued during this inspection, as documented below:
II.B.1 Reactor Coolant System Vents This item calls for the installation of RCS and reactor vessel head high point vents remotely operated from the control room.
The licensee has issued condition reports, CRs M3-97-1949 and 1950, to address problems with this item. The item will be reviewed when the CRs are resolved.
11.B.2 Plant Shieldina This item calls for radiation shielding sufficient to permit access to vital equipment, to provide protection to ope. tors, and to protect safety equipment. The licensee primarily uses installed concrete structures at Unit 3 for this purpose.
The licensee's Environmental Qualification (EO) program for equipment, under 10 CFR 50.49, has been separately evaluated by the NRC. The post-accident access to vital equipment and protection to workers is described in FSAR Chapter 12.3 and was approved by NRC as part of originallicensing in the SER and in Inspection Report 423/86-0 "
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The inspector discussed with the licensee how they assured that design modifications did not inadvertently change the shielding without appropriate review and evaluation and discussed this area with design personnel. The Design Control Manual (DCM) addresses this issue in Attachment 1 to C' apter 4, Design inputs, items 27, 28, and 29 and also in ti.e Independent Reviewer Evaluation, Form 41 A, Questions 11 and 42. DCM Form 3-2C, Design Engineering Evaluations Summary, items B, G, and P provide for additional review in various radiological areas, item B refers to NGP 5.27, Project ALARA Design Reviews, and Attachment 8.B of NGP 5.27, ALARA Design Review / Operational Considerations Checklist contains the detailed ALARA review. Post-LOCA dose evaluation, if needed, would be done by the NUSCO corporate Radiological Assessment Branch. During tours of the plant, the inspector did not identify any changes to shielding materials or shielding materials out of place.
The FSAR 12.3.1.3.2 discusses post-accident access to vital areas and defines pre-determined routes for accident mitigation personnel to use to access vital areas and equipment. The inspector walkeo down these routes with the thensee to verify they were still viable. One issue noted was that the new RCA boundary created an access problem on the designated route to the hydrogen recombiner building. In response to this, the licensee stated that Chapter 12 in certain areas could be considered historical and not currently applicable. They further stated that access to any necessary plant areas post-accident would be handled by controls in the EOPs, the emergency plan, and through the activities of the Technical Support Center (TSC) and the Emergency Monitoring Team.
When needed, the EOPs provide specific notes and cautions about access to certain areas, the necessar/ monitoring, and dose rates.
This item remains open pending correction of Sec+ ion 12.3.1.3.2 of the FSAR in the area of the predetermined, post-accident, access routes that licensee representatives have stated are no longer applicable, and which, in some cases, cannot be followed.
II.B.3 Post-Accident Samolina This item specifies the capability to sample and analyze the reactor coolant and the containment atmosphere promptly under accident conditions without excessive radiation exposure to an individual.
The licensee has identified several problems in the implementation of ttM Mm and has issued seven CRs addressing the problems. The item will be reviewec.
the CRs are resolved.
U3.Il Maintenance U3 M1 Conduct of Maintenance M 1.1 General Comments During routine plant inspection tours, the inspectors determined that the maintenance and surveillance activities observed on a random sample basis were being properly performed.
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The '.nspectors interviewed licensee field persoanel, as appropriate, to verify the adequacy of work controls.
U3 M2 Maintenance and Materiel Condition of Facilities and Equipment M2.1 (Closed) Adverse Condition Reoort ACR 07266: RCP Seal Housina Leakaae and B.olt Corrosion (Closed - SIL ltem 17'
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Insoection Scoce (92902)
The inspector reviewed the licensee's root cause asset ament and the corrective actions taken to correct the reactor coolant pump (RCP) Seal housing Leakage and S sl Housing Bolt Corrosion problem documented in ACR 07266.
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Observations and Findinas Corrosion of the number one seal housing bolts in the RCPs has been a recurring problem at t
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Since initial unit operation approximately 128 bolts have been replaced as a result of this corrosion. The seal housing is part of the reactor coolant system pressure boundary and the bolts are required to maintam the integrity of the seal housing joint. The licensee issued ACR 07266 to determine the root cause and develop corrective actions to address the problem. ACR 07221 was issued for another seal housing leakage problem. The root cause and corrective actions for ACR 07221 were folded into ACR 07266 for resolutinn.
The original number one seal housing design used SA 540, Grade B23 or B24 low alloy steel bolts and a Flexitallic, spiral wound, asbestos or graphite gasket with 304SS chevrons to make the joint seal. During the installation process, the bolts were pretensioned by relying on the thermal expansion and contraction that could be oroduced in each bolt using heater rods inserted into a hole drilled down the center of each bolt.
In the root cause determination, the chronology of RCP bolt corrosion problems was i
considered, and it was concluded that the predominance of the bolt corrosion was the result of the bolts being spiashed with borated water spillage. (Alloy steelis not resistant to boric acid corrosion.). Leakage of borated water through the joint was considered another, though lesser, ceurce of this corrosive medium. The borated water spillage source was postulated to be the external No. 3 seal leakoff splash guard which is located adjacent to the joint and which was postulated to become filled with borated water fram the No. 2 sealleakoff when certain check valves stick closed. A temporary modification of tne seal leakoff piping to isolate the No. 3 sealleakoff flow from the No. 2 sealleakoff flow was implemented with Bypass Jumper (BJ) No. 3-95-159. Regarding the joint leakage, it was concluded to be due to an inability to assure and maintain proper bolt tension with the thermal tensioning method used.
The recommended corrective actions included: formalization of the piping modifications implemented with BJ 3-95-159, change of the bolt material to inconel 718 (a material resistant to boric acid corrosion), use of a hydraulic method to preload the bolts, seal
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gasket seating surface examination and refinis.iing, and sealing gasket replacement. All corrective actions, with the exception cf the formalization of the BJ, have been completed in conjunction with the refurbishment of the RCPs to correct design deficiencies associated with the internal turning vane cap screws and locking cups. Formalization of BJ 3 95-159 piping modifications is scheduled Sr the next refueling outage (RFO 6).
The inspector revi3wed the root cause assessment and the associated recommendations for corrective actions.. Tha identified root causes of the RCP number one seal housing bolt corrosion are consistent with the character and chronology of the corrosion problems, and are considered reasonable. The conective measures are designed to both eliminate the identified corrosion initiators and to improve corrosion resistance. The inspector considered the corrective measures to be both tnorough and technically appmpriate.
The inspector reviewed the applicable design change request cad associated work orders, and discussed these docurr.3nts with the responsible design engineer. The documentation was comprehensive, and all physical work assignments have been completed. Only visual leak inriection tests remain to be performed as the RCPs are brought to normal operating temperature and pressure, c.
Conclusions The inspector concluded that the licensee's assessment of root cause and the corrective actions taken are thorough and an appropriate resolution to the RCP number one seal housing leakage and bolt corrosion problems. The remaining licensee actions to complete the proposed work related to this SIL item are scheduled and do not pose any technical concern for safe operation of the RCPs. SIL ltem 17 is considered closed.
M2.2 (Undate) eel 96-201-19: Rosemount Transmitters (Updato - Sll item 18)
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insoection Scone (92902)
As documented in inspecthn report 50-423/96-201, the NRC identii;ed Rosemount transmitters with plastic rnipping caps in spare conduit ports and with spare ports open to the environment. The licensee then found that this was not an isolated instance.
Apparently, some shipping material had been left since original construction and other material was left installed when instrumentation was returned from offsite calitration, inspection report 423/97-203 updated this SIL ltsm and identified which aspects had been corrected and which remained. A significant amount of work has been accomplished on this item over the last few months. This update addresses the remaining aspects of this issue for Units 2 & 3.
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Observations and Findinos Unit 2 The specific corrective actions to address the findi.'gs relative tc his item for Unit 2 were reviewed and found acceptable, as documented in inspection report 50-336/97-203. The
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Unit 2 broader corrective actions only addressed transmitters in the plant and not other instrumonts with problems such as switches (e.g., flow and pressure switches). Unit 2 established a detailed listing of allinstruments and has been performing inspections during the fall of 1997. Some problems were found during these inspections and automated work orders (AWOs) were issued to perform and document the work. The program appears acceptable and the work is still ongoing.
Unit 3 The specific corrective actions to address the findings relative to this item for Unit 3 were reviewed and foend acceptable, as documented in inspection report 50-423/97 203.
In ACR M3-96-070o, the licensee committed to resear,h all plant instrumentation in Unit 3 that had spare ports. An inspection was then to be performed to determine if the proper plugging material was installed. Additional instruments beyond just Rosemount tranemitters were found with shipping plugs installed and also with missing plugs.
However, follow-up NRC inspection identified that the licensee did not inspect all instruments as outlined in their corrective action plan (CAP). As a result CR M3-97-2718 was issued to document the fact that corrective action #3 of ACR M3-96-0708 was signed off without completing all of the actions, without completing RP 4.4 Assignment Completion Form, and without initiating an RP 4.2 Assignment Change Form. The licenses recommenced activities to met the original CAP provisions of ACR 0708. Lists of all instrumentation in Unit 3, so.ted by type and manufacturer, were developed. Each type of instrumentation was reviewed to determine those which had spare ports that needed inspection. All of these instruments were then inspected using procedure NUC-EDI No.
30555, Walkdowns, and also the outline plan, "ACR 0708 Shipping Plug Walkdown." This effort identified at least another 14 instruments (all non-safety related) with m;ssing plugs, that were subsequently replaced. The NRC inspector reviewed the packages and selected a sample of instruments for inspection in the plant. These were examined, as well as a number of other instruments, during plant tours. No discrepant conditions were identified.
Part of the identified preventive actions of ACR M3-96-0A'8 was the requirement for added training for Operations personnel. This particular action had not been performed and the assignment for training was closed based on the l&C training only. When this issue was identified by the inspector, the licensee issued condition report CR M3-97-2680, dated 8/15/97, to address this concern. The corrective action plan for this new CR specified that lessons learned from ACR M3-96-0708 would be evaluated and incorporated into operational experience or Operatians Manager training by December 31,1997. The inspector confirmed that, as of December 19,1997, this action had been closed by conducting training for all operators using ksson pun C97702C during training cycle 97-7.
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Conclusions Progress is being made in both Units 2 and 3 to resolve the instrument shipping plug concerns. eel 96-201-19 currently remains an issue under e1forcement review. This item remains open pending the completion of the final actions and the closure of CRs M3-96-
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0708 and M3 97 2718 for Unit 3 and the completion of work on Unit 2. SIL ltem 18 for Unit 3 is hereby updated.
U3 M7 Quality Assurance in Maintenance Act*vities M7.1 (Closed) eel 96-201-2fh Corrective Action Proarem Effectiveness (Update - SIL ltems 33 & 37)
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Insoection Scone (40500)
As documented in inspection report 50-423/96-06, the licensee's failure to take adequate corrective actions to prevent recurrence of the violation of scaffolding controis was considered an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Actions", eel 96 201-26. The inspector reviewed the licensee's apparent cause assessment and assessed the adequacy of the corrective actions taken to address this issue as well as associated " seismic ll/l " concerns, b.
Observations and Findinas During an NRC inspection team walkdown on March 12,1996, it was noted that scaffolding around chiller 3HVQ'ACU1 A was physically braced against a bracket attached to the chiller's ductwork. This was contrary to the supplementary instructions regarding seismic interactions, of the automated work order AWO M3 95 27307, used to install the scaffolding. These instructions provided the guidance to maintain a clearance of 2 inches --
around all safety-related equipment or to ensure that the scaffolding was securely clamped to a steel structure to prevent seismic interaction. Work Control Procedure, WC-1 requires the first-line supervisor to verify that the scaffolding is erected as specified. During the 1996 NRC inspection, additional discrepancies in previously installed scaffolding were also found.
These conditions represented a recurrence of a violation of scaffolding controls documented in NRC Inspection Report 50-423/95-07. In response to that violation, the licensee performed walkdowns, revised WC-1 and briefed construction supervisors, general foremen and carpenters of their responsibilities regarding the erection and inspection of scaffolding. On the basis of the chiller scaffold finding and additional discrepancies with scaffolding that had been in place when the walkdowns were performed, the team determined that the licensee's corrective actions in response to the violation were not effective in preventing termrrence. This was considered to represent an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action", eel 423/96-201-26.
The licensee issued ACR 10383 to correct the scaffolding discrepancies and to develop and implement a corrective action plan, which would address scaffolding issues in a comprehensive manner. Additionally ACRs 10585 and 8442 were issued to resolve deficiencies in other scaffold installations. Correct!/o actions for all these ACRs were closed with ACR 10383. Ineffective corrective action was cited to be the cause of scaffolding noncompliances. As corractive actions: all scaffolding installed in the plant
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was walked down and verified / corrected to meet current installation, evaluation and documentation requirements; the WC-1 procedure was changed to require a post installation walkdown by Work Planning and Outage Management (WP&OM) Engineering; and installation crafts and first line supervisors were briefed on the current installation and l
inspection requirements for scaffolding.
The inspector verified that Attachment 10 of procedure WC-1 does include the requirement for post-installation walkdown by WP&OM within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of notification that scaffold insta!!ation is complete. The procedure also specified the requirement that a minimum 2 I
inch clearance between scaffolding and safety related equipment be maintained or anchorage and bracing, cor.sistent with modes of operation, be provided to prevent seismic interaction. This requirement had formerly been specified only in the supplementary instructions for scaffolding installation and could more readily be overlooked.
The inspector reviewed and discussed with the responsible WP&OM engineer the most current semi-annual report for long term scaffolding. For each long term scaffold, there was a completed Attachment 10.3 form, in compliance with the latest revision of procedure WC-1. This review indicated that none of the scaffolding, determined in earlier inspections to be deficient, still existed. This was consistent with the corrective action plan which required the modification or removal of all deficient scaffolding.
The inspector, accompanied by the WP&OM engineer, performed walkdowns of several scaffold installations. These included units intended for both short and long term service.
The scaffolds, with the exception of one, were found to be sufficiently anchored and braced to be considered rigid. The exception, a scaffold 18' high, showed flexibility at its highest elevation. The WP&OM engineer tagged this unit to prevent its use and included a request to improve rigidity on Revision 1 to its Attachment 10.2 evaluation form. No violations of the 2 inch clearance rule were identified.
The inspector also reviewed the Scaffolding Checklist and Evaluation (Attachment 10.2, WC-1) forms for the sample of scaffolds walked down. The documents satisfied current requirements and, it'some instances, included revisions to upgrade the installations to the most current OSHA requirements. For one scaffold, a lack of compliance with the 2 inch clearance rule was noted and judged acceptable, in its evaluation documentation. For this ins %11ation, a minimum clearance of 1/8 inch was noted and accepted based on the rigidity of.he installation and the limitation to mode 5 for its use, in follow-up discussions, the WP&OM engineer responded in an acceptable and knowledgeable manner to resolve questions raised by the inspector, regarding installation and inspection practice for scaffolding, c.
Conclusions The inspector concluded that the corrective actions taken by the licensee to address the deficiencies la its scaffolding installation and inspection practices are appropriate.
Although these actions appear similar to those implemented to resolve the original concerns, they appear to be more comprehensive and, based upon NRC inspection verification activities, are being implemented effectively. Documentation is up to date and
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consistent with the latest revision of 11 applicable instructions. Those instructions include revisions that enhance seismic safety and post-installation inspection. Crafts and supervisors have been briefed in these requirements and, based on a sample review, appear to be complying with the sampled requirements.
The technicalissues associated with eel 96-20126 are considered closed. The NRC has also issued a Notice of Violation and Proposed Imposition of Civil Penalties by letter dated December 10,1997 that includes this item with the NOV letter unique identifier 02142.
At the close of this inspection the licensee had not yet responded to this letter. Both SIL ltems 33 & 37 are hereby consider to be updated.
M7.2 (Closed) Maintenance Rule insoection Issues a.
insoection Scoca (92902)
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The scope of this inspection included a review of compliance with regulatory requirements for the Mainten;nce Rule program implementation. NRC inspection report 50-423/97-80 addressed issues that were documented as a NRC Notice of Violation (NOV) 50-423/97-80-01, an Unresolved item (URI) 50-423/97-80-04, and an Inspector Follow Item (IFI) 50-423/97-80-03.
NRC NOV 50-423/97 80-01 cited the omission of ten structures, systems, and components (SSCs) from the scope of the Maintenance Rule Program. The URI 50-423/97-80-04 addressed a concern that unavailability monitoring of Unit 3 SSCs was not consistent with the NUMARC 93-01 guidance, which specified the inclusion of surveillance activities for unavailability monitoring purposes. IFl 50-423/97-80-03 addressed an issue with the performance criteria for the containment isolation valves which could mask poor performance of individual valves.
The inspector reviewed the licensee's corrective actions to address the above issues, b.
Observations and Findinas During the NRC Maintenance Rule Baseline inspection 50-423/97-80, it was found that ten SSCs, which met the scoping criteria for the Rule, were not inciudad within the scope of
the Maintenance Rule program. The ten SSCs were: fuel assemblies, fuel handling system, alternate shutdown panel, radiation monitoring panel, emergency lighting battery pack support, tunnel under the service building, fire protection, post-accident sampiing, communications, and emergency lighting systems. These SSCs are both safety-related and non-safety related SSCs which ce used in emergency operating procedures (EOPs), or to mitigate accidents. NU Letter B16495 (dated June 6,1997) was submitted to the NRC and discussed the licensee's orrective actions to address the subject violation in NOV 50-423/97-80-01. The corrective actions included: (1) a revision to the Maintenance Program Instruction PI-1,1, " Phase 1 Scoping", (2) a complete scoping evaluation using the new instructions, (3) the issuance of guidelines and instructions for Maintenance Rule program implementation as controlled instructions, and (4) development of systerr basM documents for the new systems added to the program scope, j
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The inspector noted that scoping instructions in Appendix B of Maintenance Program Instruction PI-1.1, " Phase 1 Scoping", Revision 2, dated 12/20/96, were revised to include the review of applicable FSAR chapters as a data source for the classification of SSCs.
This revision expanded the base of scoping questions for adding SSCs in the program scope. NU memorandum MP3 TS-97-041, dated February 7,1997, documented an SSC scoping evaluation using the new instructions, and this ret s in more systems being added to the Maintenance Rule scope. The additional systems included those Fbls which the NRC inspection team identified to be omitted from the Rule scope (Refereri
.U memorandum MP3 TS-97 459, December 24,1997). As of July 15,1997, systum basis documents were developed for all of the new systems (e.g., fire protection, emergency lighting, communications, or post-accident sampling systems) that were added to the program scope. Additionally, guidelines for the Maintenance Rule program implementation have been converted into controlled instructions as Engineering Department Instructions
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(EDI 30700-30750). For example, EDI 30710 provided the technical guidance for determining whether a SSC f ailure event was a " Functional Failure" within the context of the Maintenance Rule. The inspector considered the corrective actions, taken to address the NOV 423/97-80-01, to be acceptable.
URI 50-423/97-80-04 addressed a concern that unavailability monitoring of Unit 3 SSCs was not consistent with the NUMARC 93-01 guidance, which specified the iiclusion of surveillance activities for an accurate assessment of SSC unavailability. CR M3 97-0855 was generated to document and disposition this finding. A corrective action was the development of controlled instruction EDI 30700, " Maintenance Rule Unavailability Monitoring" which provides technical guidance for monitoring unavailability of selected systems within the scope of the Maintenance Rule. Section 3.3 of EDI 30700 indicated the inclusion of surveillance activities for unavailability monitoring and trending, and Section 3.4 defined the specific boundary considerations for the purposes of unavailability monitoring. As of October,1997, system basis documents for risk-significant systems have been updated to indicate the applicable conditions (e.g., surveillance activities requiring entry into TS Action Statements) for determining system unavailability.
Additionally, all systems with unavailability monitoring requirements were reviewed by the system engineers, and recommended changes to performance criteria were presented to the Maintenance Rule Expert Panel for approval (Reference memorandum MP3-TS97-392).
The inspector considered the correctivo actions taken to address the URI 423/97-80-04 as reasonable, and the item is closed.
In the Maintenance Rule Baseline Inspection report, IFl 50-423/97 80-03 addressed the issue of performance criteria for the containment isolation valves which could mask poor performance of the individual valves. AR 97012700-03 was initiated to revise the system performance criteria for application to any individual valve, penetration, or other isolation device subject to Local Leak Rete Test (LLRT) requirements. Section 4.1 of the Systern Basis Document for Containment isolation, Revision 3, July 18,1997 showed that the performance criteria for containment isolation now addresses individual valves, penetrations, or isolation devices subject to LLRT requirements. The inspector had no further concerns with this issue.
c.
Conclusions l
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The inspector verified the corrective actior-resolve the Maintenance Rule Inspection issues to be reasonable and complete. Si the corrective activities were implemented in a timely manner, the Maintenance Rule program implementation issues addressed in NOV 423/97 80-01, URI 423/97 80-04, and IFl 423/97 80-03 are considered to be closed.
U3.lli Enaineerina U3 E1 Conduct of Engineering E1.1 (Closed) eel 96-201-04: Turbine Driven Auxiliarv Feedwater Desian Concerns (Closed - SIL ltem 111 a.
Insoection Scoce (92903)
As documented in Inspection Report 50-423/96 201 the licensee changed the facility operating procedures to permit closure of the turbine driven auxiliary feedwater (TDAFW)
pump discharge valvec whenever the motor driven auxiliary feedwater (MDAFW) pump (s)
were used for steam generator water level control. This change was made without requesting a revision to the applicable Technical Specifications (TS) and was considered an apparent violation of 10 CFR 50.59 (eel 96 201-04). During this inspection, the inspector reviewed the licensee's Common Cause Assessment, the corrective actions taken to improve the licensee's performance of 10 CFR 50.59 safety evaluations, and the latest revisions to the affected plant operating procedures.
b.
Observations and Findinas Plant Information Report 3-94-060, dated March 15,1994, and Licensee Evaluation Report 94-004, dated April 14,1994, documented that the discharge piping from the TDAFW pump was classified and designed as moderate energy piping. However, during normal startup and shutdown operations, a portion of the TDAFW pump discharge piping could be subject to the high pressure discharge from the MDAFW pumps, and therefore, should have been classified as high energy line break (HELB) piping. To accommodate this deficiency, the plant operating procedures were revised to close the TDAFW disc l,arge isolation valves and isolate the injection paths whenever either MDAFW pump was used for steam
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generator water co. col during startup or shutorwn. The procedure changes were supported by 10 CFR 50.59 Safety Evaluation JJC-041894, dated May 10,1994. This evaluation determined that: the change was safe, did not involve an unreviewed safety question (USO) and, based on an interpretation of TS Section 4.7.1.2.1.a.2, did not require a revision to the TS. This last conclusion was in error and the licensee's failure to request a revision to the applicable TS is now considered a violation of 10 CFR 50.59.
Tne licensee included the subject eel in the Common Cause Assessment of Apparent Violations, dated December 13,1996. Contributing factors, such as invoking shortcu s to accelerate the activity completion coupled with inadequate training / knowledge of the 10 CFR 50.59 process, were cited as the apparent causes. Proposed corrective actions J
included: modification of plant operating procedures to no longer isolate the TDAFW discharge flow paths without entering the appropriate TS ection, revision of Nuclear Group Procedure (NGP) 3.12 to improve the 10 CFR 50.59 safety evaluation process, training on
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the revised procedures, and submittal of a TS change request to allow discharge valve closure before startup. The change in plant operating procedures, revision of NGP 3.12 and the associated training have been completed, while the intention to request a TS change has now been deleted.
The intpector reviewed Revisions 0 and 10 (the latest revision) of NGP 3.12, the 10 CFR 50.59 lesson plans, the lesson attendanco sign-off sheets, and the revised pages of Operating Procedures 3201, Plant Heatup; 3203, Plant Startup; 3206, Plant Shutdown; 3208, Plant Cooldown; and 3322, Auxiliary Feedwater System, e
NGP 3.12 defines the process for preparing safety evaluations of proposed plant changes to assure safety and compliance with 10 CFR 50.59 requirements. NGP 3.12 is clear and includes screening check sheets to simplify and standardize the process. The 10 CFR 50.59 lesson plan fully describes the 10 CFR 50.59 requirements, their intent and the methods to meet them. Sign off sheets show more than 500 personnel have received the training. Thus, Unit 3 personnel have been recently provided what appears to be adequate training in the performance of these safety evaluations. Regarding the issue of TS applicability, the revised p ocedure makes the importance of TS compliance and proper consideration clear. It is addressed in the first line of the safety evaluation screening sheet, from which it can be concluded that if a TS change is required, the 10 CFR 50.59 safety evaluation process does not apply. The most important addition to the enhanced 10 CFR 50.59 process appears to be the requirement to have PORC/SORC review all safety evaluations. This additional review by knowledgeable personnel adds a significant quality check to the process.
A review of the revised operating procedures indicated that the option to use auxiliary feedwater to feed the steam generators in Modes 1,2 and 3 has been deleted, as committed to in licensee letter B16575, dated July 14,1997. This precludes the need to close valves 3FWA*HV36 A,B,C and D, in these modes, and removes the source of the apparent TS violation. Regarding the licensee's intent to request a TS change, concerns relative to the ability of the discharge valves to hold the required back pressure were raised and the licensee decided to use only the main feedwater system for the startup and shutdown evolutions.
c.
Conclusions The licensee's corrective actions to heighten employee awareness of the importance of Technical Specifications and their proper consideration in determining compliance with 10 CFR 50.59 and to redress the source of the subject apparent violation are considered positive and appropriate. The techriicalissues associated with eel 96-201-04 are a
considered closed. The NRC has also issued a Notice of Violation and Proposed imposition of Civil Penalties by letter dated December 10,1997 that includes this item with NOV letter unique identifier 01152. At the close of this inspection, the licensee had not yet responded to this letter.
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I The licensee must still complete its resolution of the concerns with the TDAFW discharge
lines and valves 3FWA*HV36 A,B,C and D. These actions will be assessed by the review of the corrective actions for adverse condition report (ACR) 10780. Review of this ACR is documented in inspection report 50-423/97-207. Sll item 11 ves ah,o discussed and g
updated in inspection reports 50-423/97 202 and 97 207. An unresolved item and another ACR were closed in those inspection reports. With the closure of eel 96-20104 during (
this inspection, SIL ltem 11 is considerrd closed. Another related eel 96 201-05, concerning the operational compliance issues, is still open, but will be addressed in a future resident inspection report as part of SIL ltem 70, in which TS compliance and operational issues are being evaluated. ACR 10780 vvill be transferred to Sllitem 70 for concurrent closure.
M U3 E2 Engineering Support of Facilities and Equipment E2.1 JUodate - LER 98-028 00 & 01) Overcoolina of CCE Charaina Pumo tube Oil System Due to Loss of Instrument Air Concurrent with Low Service Wetu Temoerature (Update - SIL ltem 13)
R a.
Insoection Scooe.192903)
in LER 96-028-00, the licensee reported a failure scenario that could potentially result in an overcrling of both trains of the charging pump lube oil system and challenge charging pump operability. This scenario involved a loss of instrument air to ternperature control valves (3CCE*TV37A and B) in the charging pump cooling (CCE) system serving the charging pump lube oil coolers, coincident with 33*F service water (SW) temperature. On December 13,1996, in supplemental LER 96-028-01, the licensee reported the cause of the potential charging pump inoperability was inadequate initial design. This condition would result from overcooling of the lube oil system below the minimum allowable temperature of 60*F following a failure of the non-QA instrument air system (IAS),
coincident with worst case minimum SW inlet temperature to the lube oil coolers and maximum flow and maximum lube oil cooler cleanliness. Under these conditions, the air-operated CCE valves would fail open and excessive cooling of the lube oil system to 40*F would occur. During this current inspection, the inspector reviewed the licensee's engineering activities to resolve the technical concerns associated with this issue and assessed ongoing plant design modification activities.
b.
Observations and Findinas The inspector reviewed the licensee's engineering activities, which had included the installation of a temporary modification (Bypass Jumper 3-96-112) installed in February, 1997 prior to the SW (i.e., the Long Island Sound) temperature failing below 39*F. The bypass jumper was intended to divert 6 GPM of cooling water flow around the charging pump lube oil coolers to prevent overcooling of the charging pump lube oil. Prior to the SW temperature exceeding 54*F, the bypass,tumper was removed in May,1997.
Design Change Record (DCR) M3-97085 identified a permanent modification to the charging pump lube oil system. This consisted of setting the lube oil pressure regulating
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valves (3CHS*RV8511 A/B/C) to control system pressure at the pump gearbox between 20 to 24 psig undar normal conditions (as opposed to the current 15 to 18 psig) to provide assurance of adequate oil flow under low temperature, high viscosity operation. The modification included calculations performed by the charging pump manufacturer, Westinghouse (and Dresser Pumps), intended to justify 30 days operation of the charging pumps with a lube oil temperature of 48'F, equivalent to a viscosity of 700 SSU (Saybolt Seconds Universal), at a minimum SW temperature of 40*F. The licensee is monitoring the progress of the modification installation to ensure that the temporary bypass jumper would not need to be installed again as the Long Island Sound temperature decreases during this winter, included in Design Change Notice (DCN) DM3 00-1466-97, " Revise Cooling Water Temperature and Lube Oil Pressure for Charging Pumps," were relevant portions of vendor technical manual VTM No. 25212-001019, Rev 019M, which stated under " Pre Startup Checks" that: " Westinghouse recommends that the oil inlet pressure to the gear unit be monitored with a pressure switch and control room alarm. The low pressure alarm setting should be 8 psi." The inspector questioned whether a new alarm set +ing would be required, in view of the upward adjustment in the pump gearbox pressure. The licensee respor.ded by providing the alarm response procedure, OP 3353.MB3A, Rev.1, which indicated that the setpoint was less than 15 psig for greater than 15 seconds, not 8 psig.
However, the procedure had not been changed to address the change in the normal oil supply pressure from 15-18 psig to 20-24 psig, as required by the design change.
The information provided to justify the upward adjustment of the lube oil pressure in general was sufficient and technically sound with respect to the design aspects of the change, such as the heat exchanger performance and resulting temperatures, and the stress analysis, which had originally been performed for a SW temperature of 33*F prior to the initial plant startup in 1985. According to a licensee memorandum MP3-DE 97-1357, 09/19/97, which identified the various stress analysis calculations pertaining to the CCE and the safety injection pump cooling (CCl) systems, the piping of the CCE system was originally stress analyzed by Stone & Wrbster for a minimum temperature of 33*F. The inspector verified this on a sampling basis by referring to Revision 4 (12/18/92) of Calculation No. 747XD. Revision 0 had been completed 08/27/83. The results indicated that the stresses in the piping on the CCE outlet side of the CCE/SW heat exchanger, which would be the piping subjected to the coldest temperature under the currently postulated scenario, were within the allowable limits.
The licensee provided proprietary results by Westinghouse and Dresser Pacific Pumps (Order No. Y-628) from April,1976 which documented testing performed in April 1976 to determine the performance of pumps similar (but of a are@us vintage) to the Uni' 3 charging and safety injection pumps, operating at low semice water temperature
.e.,
37'F, for a period of two (2) hours, corresponding to an unspecified oil viscosity at 40*F (150 SSU at 100*F). The licensee's DCN indicated that the pumps could be run for 30 days (720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />) with SW temperature of 33*F. From the results of the testing, it did not appear that the lower SW temperature of 33*F would make any significant difference in pump performance. Regulatory Guide 1.68, Appendix C, paragraph 1e, and Reg. Guide 1.79, 52c(1) specifies that proper operation of injection pumps and motors in all design
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operating modes should be verified. The licensee was unable to provide information that showed that the NRC had accepted the above results in lieu of plant specific testing at design conditions The inspector also noted examples of possibly incomplete licensee followup to implement the resultant required chances in operational procedures, particularly since AOP 3562,
" Loss of Instrument Air," Rev. 3, 04/12/96, did not directly address overcooling of charging pump lube oil. For example, the design engineer had not included Electrical Int trumentation & Control (El&C) on the distributiori for the design change notice, lherefore, the need to change CCE temperature alarm setpoints was overlooked. The alarm response procedure for Low CCE Temperatuce, OP 3353.MB3B, Rev. 4, indicated only that the operators should maintain CCE temperature above 80*F to prevent condensation in the charging pump lube oil. Operators had not been trained to respond to this scenario where the temperature cannot be raised above 40'F. The licensee indicated that to respond to this concern, OP 3353.MB3B would be changed to direct the operators to contact the Condition Monitoring specialists to monitor moisture content of the oil, f
The lube oil pressure regulating valves were manufacturer-supplied skid mounted equipment and there are control room alarms for " Charging Pump Lube Oil Prestore LO," however, this t
equipment did not appear on the Master Setpoint List. The licensee stated that the equipment was considered very reliable based on many years of industry experience.
Further, since the manufacturer set the control values in the factory, the licensee does not believe that these particular portions of the charging system require adjustment. The licensee indicated that the charging pump lube oil pressure regulating valves setpoint would be added to the Master Setpoint List.
The inspector also requested a clarification concerning the 60* F SW temperature in the Cold Ambient Environment calculation used to address pump operability.
Conclusions A number of areas regarding LER M3-96-028 remain open, as noted above. This area will be reviewed further during the next routine resident inspection report period. SIL ltem 13 is hereby updated.
U3 E3 Engineering Procedures and Documentation E3.1 (Undatel Unresolved item. URI 50-423/95-07-10: Containment Hatch - Downaradina Sflepyioment throuah the MEPL orocram (Update - SIL ltem 25)
This item was last discussed in inspection report 50-423/97-202. During this inspection, the inspector assessed licensee actions to address the following issues, as noted.
1.
The parts numbering scheme for the Unit 3 containment hatch was confusing and difficult to follow between various documents; including the material, equipment, and parts lists (MEPL), the production maintenance management system (PMMS),
applicable drawings, md the vendor manual. This creates the potential for errors by i
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l maintenance or engineering personnel. During a subsequent review, the licensee found that all relevant drawings had not been updated to reflect various changes that had been implemented over the years. There were also some instances of conflicting data in the documents that existed from initial issuance. The licensee is re-evaluating the hatch.:omponents and parts. Where appropriate parts are being given new component identifications to simplify and clarify the documentation.
Additionally, documents are being updated. These activities are still ongoing.
2.
The most rncent MEPL (CD 789) for the hatch did not clearly specify which of the previous McPLs had been superseded and thus it was not clear which of the multiple MEPLs were still effective. The licensee reviewed the full MEPL history for the containment hatch, and concluded that it had not been properly and accurately documented New MEPL evaluations are now being performed to clearly summarize the current MEPL status of all hatch parts on the Bill of Materials (BOM). In the process of this effort, the licensee identified 12 parts that should have been designated as safety-related, but were noted in some MEPLs and the PMMS as non safety-related, in December, the licensee issued three CRs (CRs M3-97 4353, 4547, & 4548) to address this issue. Actions on this item are still ongoing.
3.
The PMMS incorrectly notes that CD 789 is the pertinent MEPL for all containment hatch BOM parts in PMMS. The licensee indicated that the PMMS will be updated to reflect the most current MEPLs, when items 1 and 2 above are complete.
4.
The acceptance criteria (reference: Maint. Form 3712X-1, Rev. 2) for the Technical Specification surveillance test did not accurately verify that the hatch interlocks function properly. However, the steps and the note within the procedure itself (SP 3712X, Rev. 5) do properly test the interlocks. The licensee developed SP 3712X, Rev. 6 and Maint. Form 3712X-1, Rev. 3, which now satisf actorily tests and documents the hatch interlocks.
URI 423/95-07-10 remains open pending completion or items 1, 2, & 3 above. SIL ltem 25 is also hereby updated.
U3 E8 Miscellaneous Engineering issues E8.1 IClased) Unresolved item 50-423/96-01-08: Slave Relav/Overlao Test Deficiencies (Closed - SIL ltem 24)
Reference: LER 97-017-00, LER 97-017-01, LER 97-017-02
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40 Inspection Scoce (37550)
The inspector reviewed corrective actions taken by the licensee to ensure that surveillance procedures are adequate to ensure that all portions of the safety related logic circuits are tested as required by plant technical specifications, b.
Observations and Findinas On January 10,1996 the NRC issued Generic Letter No. 96-01, " Testing of Safety-Related Logic Circuits." in this letter the NRC staff requested, in part, that licensees :
1)
Compare electrical schematic drawings and logic diagiams for the reactor protection system, EDG load shedding and sequencing, and actuation logic for the engineered safety features systems against plant surveillance test procedures to ensure that all portions of the logic circuitry, including the parallel logic, interlocks, bypasses and j
inhibit circuits, are adequately covered in the surveillance procedures to fulfill the TS requirements, This review was also to include relay contacts, control switches,.
and other relevant electrical components within these systems, utilized in the logic circuits performing a safety function.
2)
Modify the surveillance procedures as necessary for complete testing to comply with the technical specifications. Additionally, the licensee could request an amendment to the technical specifications if relief from certain testing requirements could be justified.
The licensee's initial response to GL 96-01 stated that in 1993 an overlap testing task force had performed a review of surveillance testing to ensure that TS requirements were
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met. The licensee concluded that the only action necessary to comply with the requested actions of the GL was to review plant modifications that had been perferrned after the completion of the task force reviews. The review of modifications was completed and no problems were identified, in 1997, the NRC reviewed the adequacy of safety system logic circuit testing (NRC Inspection Report 50-423/97-01) during an inspection of Unresolved item 50-423/96-01-08. As a result cf testing discrepancies idenCfied by the inspector, the licensee performed addit',nal reviews. The licensee reviews also identified discrepancies and resulted in the licenste de::iding to reconsider its position that previous reviews were adequate to meet the requested actions of GL 96-01. The licensee subsequently obtained the services of a contractor to perform a complete review of technical specification surveillance procedures to ensure the requested actions of GL 96-01 had been accomplished.
As a result of the NRC, licensee and contractor reviews, portions of several circuits were found to not have been tested as required by technical specifications. These findings were
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41 reported to the NRC in LER 97-017 00 and supplements -01 and -02 and are summarized below.
The tripping of the reserve station service transformer (RSST) circuit breaker and
emergency bus tie circuit breakers were not tested for a degraded voltage or undervoltage condition. The licensee has revised the procedure for both trains and i
has successfully tested the "B" train. Subsequent to the end of this inspection period, the "A" train was also satisfactorily tested.
The operation of several auxiliary feedwater system valves were not verified to
actuate on a steam generator lo lo level signal. The affected test procedures have been revised and successfully performed cn the train "A" valves. The "B" train valves have been verified to be operable during a post-modification test and will also be tested again in accordance with the surveillance procedure.
The main steam valve building ventilation damper interlocks were not fully tested.
- On a safety injedion signal the intake damper controllers send an isolation signal to the opposite Nin exhaust damper and this feature was not being verified. The applicable surveillance procedures will be revised and performed prior to the plant entering Mode 4.
The sequenced automatic restart of the control room chillers and the instrument and
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power testing. The applicable surveillance procedures w;ll be revised and performed prior to entry into Mode 4.
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Other test deficiencies, determined to not be reportable, were identified and documented in condition reports. All deficiencies within the scope of the GL 96-01 are scheduled to be resolved prior to plant restart.
c.
Conclusions The inspectcr discussed this issue with licensee engineers and reviewed the following:
the scope of the review, a sample of drawings and related documentation, e
a sample of the deficiencies identified, e
several surveillance procedures that had been revised to resolve deficiencies, and; e
the results of testing performed to resolve review findings.
e The inspector concluded that the scope of the review was appropriate and in accordance with GL 96-01. The licensee selected a contractor that was experienced in this area and the licensee maintained ownership and provided good oversight of the project. The review results were thoroughly documented and included marked up electrical drawings that show where all portions of the circuits are tested. The procedure revisions that were reviewed were appropriate and properly resolved the deficiency. The deficiencies were limited to small portions of the circuits and in no case was there a significant portion of any of the
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circuits that was not being tested in the past. All of the tests performed tn date were satisfactory and no instances of inoperable equipment were identified.
The failure to have adequate surveillance procedures to test the safety-related logic circuits is a violation of plant technical specifications (VIO 50-423!.,7 208 04). The inspector noted that information regarding the cause of the violation and corrective actions have already been submitted on the docket in LER 97-017 (including supplements 01 and 02)
and a letter from NNECO to the NRC dated April 3,1997, " Updated Response to Generic Letter 96 01 Testing of Safety-Related logic Circuits." Based on this information, an adoitional response to the notice of violation may r.ot be required.
Overall, the inspector concluded that the licensee corrective actions were comprehensive, well controlled and thoroughly documented. Unresolved item 50-423/96-01-08, LERs97-017 00,97-017 01, 97 017 02 and SIL ltem 24 are closed.
IV Plant Suonort (Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistry Controls R1.1 Contaminated Unit 3 Intake Structure sediment (71750)
During this inspection period, the licensee was removing sediment (sitt and debris such as L
shells and seaweed) from the Unit 3 circulating water intake canal. The dewatered sediment was collected and shipped to the Waterford D ndfill. During this process, after a number of truckloads of ma'erial were transported, the licensee sampled the sediment and -
on December 3 detected contamination. The results of two sample counts found small amounts of Cesium 137 and Cobalt 60 in the material. CR M3-97-4378 was issued to document the problem and identify appropriate corrective actions.
As a result of these positive sample resdts, the licensee terminated shipments to the landfill and took samples of the material previously deposited there. The results of these samples were negative. ' The NRC subsequeritly took three representative split samples of the landfill sediment with the licensee. The NRC's samples were packaged and sent to the NRC Region I office in King of Pruss;a, Pennsylvania to be counted. The NRC's and licensee's results identified no contaminated material attributable to the Millstone station.
All of these samples were counted to a lower limit of detection (LLD) which was more conservative than that specified by NRC requirements and therefore more likely to yield positive results. The inspector noted that if an even more conservative LLD was used, it may have been possible to detect traca amounts of radioactivity. On December 19, the licensee removed the material from the Waterford landfill and took it back to the Millstone site. The licensee sampled the affected area whore the sedimont had been and verified no contamination remained.
The NRC will review the licensee's procedures and co rective actions following the identification of contamination of the intake struc.ure materialin a future inspection. This item is considered unresolved. (URI 53-423/97-208-05)
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43 R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Imorovements in Housekeeoina and Plant Material Condition at Unit 2 During plant tours of Unit 2 conducted throughout 1997, the resident inspectors have observed continualimprovements in the area of plant housekeeping. Painting efforts, particularly in the turbine building and auxiliary feedwater pump rooms, have not only improved the plant's visual appearance but more importantly servcs to preserve plant equipment. Plant material condition improvments such as repairs of leaks have also resulted in improved housekeeping. Overall,1997 ended with 3 drip containers installed for active radiological leaks, a significant reduction from the 80 catch containers installed in June 1996. Particularly noteworthy was the large effort to repair a leak of a few drops per minute on the non-radiological (reactor building closed cooling water) side of the shutdown cooling heat exchanger. In addition, in 1997, the contaminated square footage in Unit 2 radiological controlled areas was reduced frc,m 4784 square feet of recoverable square footage to 1048 square feet. Although housekeeping and plant preservation activities are ongoing, the licensee efforts thus far have been good which reflects management's highe:
standards arid expectations.
V. Mannaggaem idealnas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at separate meetings in each unit at the conclusion of the inspection. The licensee acknowledged the findings presented.
X1.1 f8nal 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 highligL*d the need for additional verification that licensees were complying with UFSAR con..T tments. All reactor i
inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures and parameters.
While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. An inconsistency was noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspectors, as is documented in Section U3.07.2 of this inspection report.
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lNSPECTION PROCEDURES USED IP 37550:
Engineering IP 40500:
Licensee Self Assessments Related to Safety Issues inspections IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92700:
Onsite follow-up of Written reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Follow-up Maintenance IP 92903:
Follow-up Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED Ooened URI 245/97 208-01 CONFLICTING FUEL SPECIFICATIONS (SECTION U1.01.2)
URI 336/97-208-02 VERIFY PROPER OPERATION AND SENSITIVITY OF WIDE RANGE NI DRAWER (SECTION U2.M3.1)
VIO 336/97 208-03 FAILURE TO RESTRAIN TEMPORARY EQUIPMENT IN SAFETY-RELATED AREAS (SECTION U2.E1.1)
VIO 423/97 208-04 FAILURE TO HAVE ADEQUATE SURVEILLANCE PROCEDURES TO TEST SAFETY RELATED LOGIC CIRCUlTS (SECTION U3.E8.1)
URI 423/97 208-05 CONTAMINATED UNIT 3 INTAKE STRUCTURE SEDIMENT (SECTION IV.R1.1)
Closed URI 245/95-81-01 U1.E7.1 eel 423/96-201 26 U3.M7.1 VIO 423/97-80-01 U3.M7.2
- URI 423/97 80-04 U3.M7.2 IFl 423/97 80 03 U3.M7.2 eel 423/96-201-04 U3.E1.1 URI 423/96-01-08 U3.E8.1 Discussed eel 336/96-201-42&43 U2.E8.1 eel 423/96-201-19 U3.M2.2 URI 423/95-07-10 U3 E3.1 LER 423/96-028-00/01 U3.E2.1 The followino LERs were also closed durino this insoection:
245/96-053-00 U 1.M8.1 245/96-063-00/01 U1.M8.2 423/97-04 U3.04.1 423/97-017 00/01/02 U3.E _ - - - - - _ _ - _ - _ -
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LIST OF ACRONYMS USED ACR(s)
adverse condition report (s)
ALARA as low as reasonably achievable AOP(s)
abnormal operating procedure (s)
AWO(s)
automated work order (s)
BOM bill of materials CCE charging pump cooling CFR Code of Federal Regulations CMP configuration management plan CR(s)
condition report (s)
DCN(s)
design change notice (s)
DCR design change record DDR(s)
design deficiency report (s)
DRS Division of Reactor Safety EDG(s)
emergency diesel generator (s)
EDI engineering department instruction eel (s)
escalated enforcement item (s)
El&C electrical instrumentation & control EOP(s)
emergency operation procedure (s)
EQ environmental qualification ESFAS emergency safety features actuation system FSAR Final Safety Analysis Report GIP (s)
generic implementation procedure (s)
GL Generic Letter
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epm gallons per minute GTG gas turbine generator HELB high energy line break ICAVP Independent Corrective Action Verification Program IFl inspector follow item LCO limiting condition for operation LER(s)
licensee event report (s)
LLD lower limit of detcetion
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LLRT local leak rate test LOCA loss of coolant accident MCCB(s)
molded case circuit breaker (s)
MDAFW motor-driven auxiliary feed water MEPL(s)
material, equipment, and parts list (a)
NCR(s)
nonconformance report (s)
NGP(s)
nuclear guidance procedure (s)
NI nuclear instrumertation NNECO Northeast Nuclear Energy Company NPDES National Pollution Discharge Elimination System NRR Nuclear Reactor Regulation NSAB nuclear safety assessment board NSIC Nuclear Safety Information Center NUMARC Nuclear Management and Resources Council
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NUQAP Northeast Utilities Quality Assurance Program NUREG Nuclear Regulation NUSCO Northeast Utilities Service Company OCA Office of Congressional Affairs OEDO-Office of Executive Director for Operations PAO Public Affairs Office PDR Public Document Room-PMMS production maintenance management system PORC plant operation review committee QA qutSty assurance -
QAS Quality and Assessment Services QSS quench spray system RCP(s)
reactor coolant pump (s)
RCS reactor coolant system RFO refueling outage RG-Regulatory Guide RHR residual heat removal RSST reserve station service transformer SBGT-standby gas treatment SER(s)
safety evaluation report (s)
SIL-significant item list SORC site operations review committee SPO-Special Projects Office SSC(s)
structures, systems, and component (s)
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'SSU-saybolt seconds universal SW service water TDAFW turbine driven auxiliary feedwater TMI Three Mile Island TS(s)
technical specification (s)
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updated final safety analysis report URl(s).
unresolved item (s) -
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USO(s)
unresolved safety question (s)
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VTM vendor technical manual WC work control WP&OM work planning & outage management i
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