IR 05000336/1988006

Insp Rept 50-336/88-06 on 880208-0321.No Violations Noted. Major Areas Inspected:Previously Identified Items,Plant Operations,Surveillance,Radiation Protection,Physical Security,Fire Protection & Review of Periodic Repts

ML20151G950
Person / Time
Site:	Millstone
Issue date:	04/13/1988
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20151G882	List: IR 05000336/1988006 ML20151G879
References
50-336-88-06, 50-336-88-6, GL-81-21, IEB-85-003, IEB-85-3, NUDOCS 8804200194
Download: ML20151G950 (19)

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U.S. NUCLEAR REGULATORY COMMISSION REGION I ,

l Report: 50-336/88-06 Docket No: 50-336 License No: DPR-21

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Licensee: Northeast Nuclear Energy Company Facility: Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Unit 2 Dates: February 8, 1988 through March 21, 1988 i

Inspectors: Peter J. Habighorst, Resident Inspector William J. Raymond, Senior Resident Inspector Eben L. Conner, Project Engineer, DRP Section 1B  :

Approved: dh 0 e)* 4/lT/PT E. C. McCabe, Chief, Reactor Projects Section 3B Date Inspection Summary: February 8 - March 21,1988 (Report 50-336/88-06) .

Areas Inspected: This inspection included routine NRC resident (135 hours0.00156 days <br />0.0375 hours <br />2.232143e-4 weeks <br />5.13675e-5 months <br />), and.

, region-based (17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />) inspection of previously identified items, plant operations, surveillance, radiation protection, physical security, fire protection, Temporary Instruction (TI) 2515/86, mechanical and hydraulic snubbers, and review of periodic and special report Results: No violations or unsafe operational conditions were identified. Addi-tional follow-up is warranted on control of overtime, I.E. Bulletin 85-03, and fire t protection for auxiliary feedwater isolation valves.

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8804200194 880413 -

PDR ADOCK 05000336 Q DCD .

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t TABLE OF CONTENTS l Page 1.0 Persons Contacted.................................................... 1 2.0 Summary of_ Activities................................................ 1 3.0 Licensee's Action on Previously Identi fied Items. . . . . . . . . . . . . . . . . . . . . 1

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3.1 (0 pen) Violation 87-16-01: Fire Protection for Auxiliary '

Feedwater Isolation Valves 2FW43A & B......................... 1 3.2 (0 pen) IE Bulletin 85-03, Motor Operated Valve (MOV) Common-  !

Mode Failure During Plant Transients Due to Improper Switch Settings...................................................... 2 3.3- (Closed) Unresolved Item 87-25-05: Control Room Radiation....... 4 ;

3.4 (Closed) Violation-87-25-02: Vital DC Chillers Inoperable....... 4 ,

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3.5 (Closed) Unresolved Item 87-25-01: Additional. Information on the Chilled Water System...................................... 5 ,

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A.0 Observation s o f Phys ical Securi ty. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 !

t 4.1 ' Vital Area Alarm De-Activation.................................. 5 [

5.0 Plant _ Tours and Operational Status Review..........................., 6 ,

5.1 Safety System Operability....................................... 7 5.2 No Fire Watch During Routine Housekeeping....................... 7 5.3 Reactor Coolant System (RCS) Unidentified Leakage............... 8 5.4 Engineering Safety Feature Integrated Test Update............... 9

6.0 Temporary Instruction (TI) 2515/86: Inspection of Licensee's Actions r

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Taken to Implement Generic letter 81-21, Natural Circulation Coo 1down........................................................... 10 j Surveillance......................................................... 13 i

'8.0 Mechanical and Hydraulic Snubber Inspection.......................... 13 ;

9.0 Allegation RI-88-A-003, Excess Hours Worked at Millstone 2........... 14 ,

t 10.0 Failure of "D" RCP Seal.............................................. 15 i i

11.0 On-Site Plant Operations Review Ccmmittee (P0RC)..................... 16 i

! 12.0 Review of Periodic and Special Reports............................... 17 ;

13.0 Management Meeting................................................... 17 f

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OETAILS 1. Persons Contacted Mr. S. Scace, Station Superintendent Mr. H. Haynes, Station Services Superintendent Mr. J. Keenan, Unit 2 Superintendent Mr. J. Riley, Unit 2 Maintenance Supervisor Mr. J. Smith, Unit 2 Operations Supervisor Mr. D. Kross, Unit 2 Instrument and Controls The inspector also contacted other members of the Operations, Radiation Pro-tection, Chemistry, Instrument and Control, Maintenance, Reactor Engineering, and Security Departaient . Summary of Activities Millstone 2 began the inspection period in cold shutdown while completing the ;

Cycle 9 refueling and maintenance outage. On February 13, the unit commenced heat-up to normal operating temperature and pressure. The heat-up was aborted on February 14, due to a failed "0" Reactor Coolant Pump seal (Section 10.0).

On February 16, heat-up recommenced, and the reactor was made critical on February 18 at 5:28 p.m. On February 25, the unit was at 100% power, and remained at that power level through the end of the inspection perio The following activities were addiessed by the inspector during the recent outage: in-leakage testing of the control room, observation of plant heat-up and approach to criticality, verification of high pressure safety injection (HPSI) system alignment during start-up, completion of the Engineered Safety Feature (ESF) integrated test, observation of Control Element Assembly (CEA)

drop times, mechanical and hydraulic snubber review, and Plant Operations Re-view Committee (PORC) meetings. The inspector observed planning and imple-mentation of containment inspection prior to start-up physics testing, and utilization of a second dedicated senior reactor operator (SRO) in the control room to track prcrequisites and requirements for heat-up. Good overall direction and overview by the licensee were note . Licensee Action on Previously Identified Items 3.1 (0 pen) Violation 87-16-01: Fire Protection for Auxiliary Feedwater Isolation Valves 2FW43A & B (92701)

This item concerned the lack of a 20 foot separation between redundant valves 2FW43A & B as required by 10 CFR 50 Appendix R Section 111. NRC and licensee review during inspection in July 1987 identified no safety concern. The licensee instituted compensatory measures by start-ing and maintaining an hourly fire patrol of the area. In the October 23, 1987 response to the Notice of Violation, the licensee stated he would seek an exemption from the regulations, and that the fire patrol would be maintained until the staff approved the exemption reques , _

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The licensee submitted a request for exemption from the Appendix R re-quirements relative to 2FW43A & B by letter dated February 29, 1988 and notified the inspector that he intended to discontinue the fire patrol of the area. The reason for the action was that there was no benefit of having the patrol since, as documented in the ba;es for the exemption request, there were no safety concerns with the existing plant configu-rations. The licensee requested NRC concurrence in the intended actio The inspector toured the valve area to review the area for fire hazards, and reviewed the Fire Hazards Analysis provided in the February 29 ex-emption request. The inspector noted that there were no transient com-bustibles in the area. The inspector noted further that the valves are designed to fail open upon loss of power and/or air supply to the valve positioners. The inspector cancurred with the licensee's tecnnical de-termination that no safety hazard existed since any fire in the area affecting both valves would not prever,t the valves from opening, or pre-vent the auxiliary feedwater system from performing its intended functio After consultation with NRC management, the inspector informed the lic-ensee on March 4, 1988 that the NRC staff did not concur with discon-tinuing the fire patro The inspector informed the licensee that the patrol should be maintained until the NRC approves the exemption request or approves discontinuing the fire patro The licensee acknowledged the inspector's comments and stated that the fire patrol would be main-tained. The inspector verified periodically during the inspection period that the fire patrol covered the are '

The inspector had no further comments at this tim Resolution of the licensee's exemption request will be followed up in subsequent routine inspection .

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3.2 (0 pen) IE Bulletin 35-03, Motor Operated Valve (MOV) Common Mode Failure During plant Transients Due to Improper Switch Settings (92702)

The licensee's June 11, 1986 response addressed six specified actions related to the subject bulletin. (This response was reviewed for time-11 ness and content in Inspection Report 50-245/86-17 for Millstone 1.)

IE Bulletin 85-03 specifies that motor-operated valves (MOVs) in the high pressure coolant injection, core spray, and emergency feedwater systems should be tested for operational readiness in accordance with 10 CFR 50.55a(g), and that licensees should develop and imple.'ent a program to ensure that components are selected, set, and maintainet properly. The licensee's reply concluded for Millstone 2 that the reviev specified by

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IEB 85-03 applied to the Auxiliary Feedwater (AFW), the Hig5 Pressure Safety Injection (HPSI), and the Chemical and Volume Control (CVC) sys-

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, Design Bases for Motor-Operated Valves (MOVs)

The licensee was to review and document the design basis for each r MOV including the maximum valve differential pressure expected dur- t ing both opening and closing for both normal and abnormal event The licensee identified 4 AFV system MOVs, 16 HPSI system MOVs, and 3 CVC system MOVs to be included in the program. In addition, the l licensee included 2 power-operated relief block valve MOVs (2RC-403 and 2RC-405) in the program. The specified design differential pressures for the 19 of the 25 included valves were equal to or i greater than the normal and abnormal event maximum differential pressure '

In the June 11, 1986 response, the licensee justified six (6) MOVs I with specified design differential pressures less than event maximum differential pressure For the Terry Turbine steam supply isola-tion MOVs (2 MS-201 and 202), the licensee found the specified dif- '

ferential pressure of 900 psi (normal operating steam pressure) ,

acceptable based on both redundant steam supply MOVs being normally t open and the worst case maximum event pressure being limited to 1065 psi. For the HPSI discharge header crosstie valves (2-51-653 ,

and 655), the licensee found the specified differential pressure j

, of 1200 psi acceptable based on no safety injection actuation signal !

l (SIAS) for these valves, the requirement that one valve be closed i for separation, and maximum discharge pressure being 1250 ps For-the HPSI injection header isolation valves (2-SI-654 and 656), the !

licensee found the specified design differential pressure of 1200 l psi acceptable based on the MOVs being normally locked open and not i being required to operate for safety injection. The inspector had i

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no further questions on these valve l

b. Translate the Specified Design Differential Pressure to the Correct MOV Switch Settings

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, The licensee's response outlines a plan to determine the proper switch settings using a combination of analytical and empirical dat l

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The inspector found that this engineering had been performed but this data was not reviewed during this inspectio The inspector's review will be performed after the final report is submitted.

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c. Testing of MOVs to Ensure Valve Switch Settings The licensee committed to stroke test a sufficient sample of MOVs against a maximum expected differential pressure and use these re-sults to verify the theoretical torque swi'.ch setpoints. MOVs where differential pressure testing was not possible were to be stroke-tested using the Motor-Operated Valve Analysis and Test System (M0 VATS), to the extent practical, to verify that the settings de-fined have been properly implemented. To this end, NNECO purchased MOVATS equipment and initiated MOV testing at Millstone 2. The in-

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spector reviewed Special Procedure 87-2-5, Procedure for Testing Limitorque MOVs using MOVATS, and observed the physical testing of selected MOVs. The licensee had two testing crews working to com-plete the testing of 13 MOVs, including flow testing of 8 HPSI MOVs, during the just completed refueling outage. The remaining 12 MOVs are scheduled to be static-tested during plant operation. The lic-ensee stated that M0V findings / resettings will be provided in the final report, Review / Revise Procedures to Ensure Correct MOV Switch Settings

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The licensee committed to review and revise procedures to ensure

that correct switch settings are determined and maintained. The licensee is working to have the necessary procedure changes in the near future. This aspect remains ope R_eport e the Results of MOV Design Basis Review and Provide the Schedule for Corrective Actions

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The licensee's June 11, 1986 letter provides the results of MOV design basis review and commits to complete the other actions for

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Millstone 2 a couple of months after the end of the current refuel-ing outage. The licensee has established a coordinated and compre-hensive MOV testing program that addresses the concerns of IEB 85-0 They now plan a composite report for all 4 units (Millstone 1, 2, and 3 and Haddam Neck) to be submitted to the NRC prior to July 1, 1988. This schedule is acceptable to the NRC. The NRC will review the final report when it is receive .3 (Closed) Unresolved Item 87-25-05: Control Room Radiation (93702)

The licensae continued testing of the leak tightness of the control room envelope during this inspection period. On February 11, the licensee successfully completed inservice test T88-05 and verified that control room inleakage was less than the allowable 100 scfm. To do so, the lic-ensee used the emergency technical specification (TS) change for TS 4.7.6.1.e.3 by placing the control room air conditioning system in the isolation /recirculationmode(accidentcondition). The inspector veri-fied the licensee met the provisions of the emergency technical specifi-cation change and complied with the limiting conditions of operations (LCO). No inadequacies were noted. This item is close .4 (Closed) Violation 87-25-02: Vital DC Chillers Inoperable (93702)

The licensee responded to this item by letter dated February 10, 198 Licensee actions to restore the vital DC chillers to operable status were reviewed and found acceptable in Inspection 87-25. The licensee reported that the vital DC chillers would be replaced by March 1988 and that emergency operating procedures would be changed to list operator contin-gency actions to establish alternate cooling methods if the chillers were

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not available. The inspector noted that the chiller heat exchangers were ,

replaced during the 1988 refueling outage. The licensee initiated ac-tions on 1/18/88 to change the applicable emergency operating procedure The procedure change commitment was assigned controlled routine number CR 0587-55 with a scheduled completion date of 11/28/88. The inspector identified no inadequacies with the scheduled completion dato, based on the continued operability of the chilled water heat exchangers, the changes to OP 23150 and 2330C discussed below, and the operators' general knowledge of the compensatory actions needed to provide alternate cooling to the room Based on the above, the licensee's actions on this item were satisfactory and this item is close .5 (Closed) Unresolved Item 87-25-01: Additional Information on the Chilled Water Syst.em The licensee responded to this issue by letter dated 12/4/87 to describe the history of the problems on the vital chilled water heat exchangers and the bases for his actions and schedule to restore the units to an operable condition. The licensee stated that administrative procedures presently in effect for conducting 10 CFR 50.59 evaluations art more thorough and comprehensive than in the past and would better document bases for actions involving inoperable equipment. Additionally, the licensee revised system operating procedures for the vital electrical switchgear cooling (OP 23151, Change 1,11/3/87) and for the chilled water system (OP 2330C, Change 4,11/3/87) to provide additional guidance to the operators in the event normal cooling is lost. The inspector reviewed the instructions and identified no inadequacies. This item 's close .0 Observations of Physical Securits (81064)

Selected aspects of site security were verified for proper implementation during inspection tours. The aspects of site security included access con-trols, personnel and vehicle searches, personnel monitoring, placement of physical barriers, compensatory measures, and guard force response to alarms and degraded condition .1 Vital Area Alarm De-Activation On March 11, at 8:16 a.m., the licensee reported a security event unc;r 10 CFR 73.71(c). A unit 2 vital area access door was closed and locked, but the associated alarm was deactivated. Upon discovery, the licensee posted the door and searched the are No discrepancies were note The licensee conducted an investigation to determine why the alarm was deactivated. On March 10, the computer services department was deacti- ,

vating data points still active in the computer system but not required *

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to be functional. The licensee's work order to accomplish this task was l MP-88-01783. The inspector interviewed the licensee to determine the !

cause for deactivating a vital area access point. The licensee concluded personnel error caused an improper alann deactivation. In further in-terviews with the licensee, ic was concluded that the vital area access t point alarm was deactivated for approximately 23 hour2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> i

According to the licensee, this alarm discrepancy should have been de- -l termined by an eight-hour surveillance Security Equ'pment Surveillance ;

Procedure (SEP) 5073. This surveillan'ce directs the console operator to compare the inactive points list to tha security compensatory measures currently in place. During this particular event, SEP-5073 was not per-formed. During his followup of the event, the licensee determined that SEP-5073 was not completed for about two weeks prior to the event. The licensee stated that completion of this surveillance was not tracked during routine shif t activities by the console operato The licensee's corrective actions are to provide a checklist for all console operators to complete and document on an 8-hour shift basis. The inspector has no further questions in this area. The inspector reviewed the last three surveillann checks completed per SEP-5085 prior to the event on the vital access point in question. This test is completed periodically to verify vital access point alarm functions are operabl The completed test results showed no discrepancie The inspector concluded this was a licensee-identified violation. The inspector reviewed the past year Security Event Reports (SERs) to deter-mine licensee's corrective actions for a previous violation and deter-mined if past corrective actions could have precluded this particular event. The inspector also reviewed the reporting requirements under 10

, CFR 73.71(c). No discrepancies were noted. The inspector concluded the j event 1) was identified by the licensee; ii) is of severity level V or i

or IV; iii) was reported as required; iv) was acceptably corrected, in-cluding measures to prevent recurrence; a.'d v) was not a violation that could reasonably be expected to have been corrected by prior corrective actions. Based on the above, no violation will be issued (LII 88-06-02),

i 5.0 Plant Tours and Operational Status Review (71707)

The inspector observed plant operations during regular and backshift tours i

of the following areas:

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! Control Room Auxiliary Building l Vital Switchgear Room Enclosure Building

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Turbine Building Fence Line (Protected Area)

Intake Structure Control room instruments were observed for correlation between channels, pro-per functic31ng, and conformance with Technical Specifications. Alarm - con-ditions in effects and alarms received in the control room were reviewed and discussed with operators. Posting and control of radiation, contamination,

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l and control of high radiation areas were inspected. Usage and compliance with l Radiation Work Permits (RWPs) and uses of required personnel monitoring de- ,

vices were checked. During plant tours, logs and records were reviewed to ensure compliance with station procedures to determine if entries were cor-rectly made, and to verify correct communication and equipment status. Re-cords included various operating logs, turnover sheets, and tagout log Backshift inspections of the control room were performed on February 10 at 1:00 a.m., on February 16 at 9:00 p.m., on March 10 at 5:00 p.m., and on March 20 at 7:00 p.m. Routine power operations and refueling outage activities were observed. Operators were alert and attentive to plant conditions. No abnor-mal conditions were observe .1 Safety System Operability (71710)

Emergency systems were reviewed to verify they were operable in the standby mode. The systems reviewed were the high pressure safety in-jection (HPSI) system and the auxiliary feedwater (AFW) system. The inspector used line-up procedures OPS form 2604E-2 for the HPSI system, and OPS form 2610C-2 for the auxiliary feedwater system, to determine positions for major flow path valve This review verified the valve line-up procedures agreed with the respective piping and instrument drawings 26015 and 26002/26005. No inadequacies were noted. The safety system review also considered operable normal and emergency power sup-plies, indicators and controls functioning properly, visual indication for component leakage, lubrication, locations of ignition sources or flammable materials in the vicinity, and the overall condition of the system. No inadequacies were note The inspector reviewed the most recent technical specification surveil-lances on the HPSI and AFW systems to verify the system operability re-quirements were met, test results were acceptable, and test frequencies were me Items reviewed were:

Technical Specification Surveillance 4.7.1.2.la, 2a, 3, 4 OP-2610A-1 "A" AFW Operability 4.7.1.2.la, 2a, 3, 4 OP-2610A-2 "B" AFW Operability 4.5.2.a.1 and 4.5. OP-2604A-1 Facility I HPSI Operability 4.5.2.a.1 and 4.5. OP-26040-1 Facility II HPSI Operability No inadequacies were identifit .2 No Fire Watch Ouring Maintenance Housekeeping (93702)

On 3/14 at 10:30 a.m., in the turbine building at the east 56 foot area, the inspector observed grinding operations on a temporary storage cag The grinding was g=nerating sparks. There was no fire watch. The in-spector asked why. The licensee secured the work, posted a fire watch, and resumed work on the temporary storage cag .

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The inspector reviewed the licensee's fire hazards analysis. The heat potential for this location is 37,535 BTU /sq. ft., with the combustible material being cables and main turbine lube oil (storage and transient).

Inspector review concluded that hot work not properly controlled could have created a significant fire hazard. However, the inspector noted no transient combustible materials in the area and no potential to ad-versely impact safety-related equipment. Therefore, the inspector con-cluded that the safety significance was minima The licensee informed the inspector that work on this temporary storage cage was considered housekeeping and was therefore not governed by a work order. (ACP-QA-2.02C, the Work Order procedure, identifies under what conditions a fire watch shall be implemented.) The inspector asked the licensee to review his administrative controls as necessary to assure activities involving ignition sources are appropriately controlled per ACP 2.058, Control of Combustible Materials, flammable Liquids, Com-pressed Gases, and Ignition Sources, if work orders are not applicabl The licensee has informed first-line supervision of this occurrence, and of the need to determine whether fire watches are needed on specific jobs not utilizing a work order. This item is unresolved pending completion of licensee actions and subsequent review by the NRC (UNR 88-06-01).

5.3 Reactor Coolant System (RCS) Unidentified Leakage (93702)

On 3/8 at 8:30 a.m., with the unit at full power, the licensee reported to the inspector an increase in unidentified leakage in containment to 0.37 gpm (an increase from the 0.135 gpm calculated when the unit began full power operation on February 25 after the Cycle 9 refueling outage).

The Technical Specification limit for unidentified leakage (TS 3.4.6.2)

is 1 gpm. The containment sump boron concentration was 182 PPM. RCS boron concentration was 871 PPM. On 3/9 at 12:15 p.m., the licensee entered containment to search for the source. No leakage was locate On 3/10, the licensee entered containment, again, for two reasons. The first was to repair SI-661, a solenoid-actuated pneumatic globe valve from the #3 Safety Injection Tank (SIT) to the primary drain tank (PDT).

SI-661 had failed leak rate testing during the outage, and the licensee noted level decreases in #3 SIT and an increased frequency of filling the #3 SIT to maintain the level within Technical Specification 3.5. limit The inspector verified, daily, the level and pressure require-ments in all four SIT tank No inadequacies were noted. As a result of leakage past $1-661, the licensee prepared 2-ENG-150, Rev. O, an ap-pendix to the RCS unidentified leak-rate calculation, to account for leakage from the #3 SIT to the PDT. This leakage is not accounted for in the RCS leakage calculation procedure (SP203), but the PDT level changes are included in the calculation performed by the process compute The inspector independently verified (utilizing SP-203) that the above condition leads to an erroneous result for unidentified leakag The licensee's second reason for entering containment on 3/10 was to recheck

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any possible unidentified leakage paths. No leak points were foun Valve SI-661 was successfully repaired at 6:10 p.m. on 3/10. Subse-quently, the licensee terminated use of 2-ENG-15 On 3/11, the licensee's water inventory balance calculated 0.38 gpm un-identified leakage. The inspector utilized data points from the process computer and independently calculated unidentified leakage using SP-203 for guidance. No discrepancies were note The licensee also monitored containment radiation, containment sump pumping frequency, steam generator activity, and total RCS activity trends to detect unidentified leakage. No sources of leakage were iden-tified. As of 3/18, the calculated unidentified leakage was 0.459 gp The inspector will continue to monitor licensee activities in this are .4 Engineered Safety Feature Integrated Test Update (62703)

In NRC Inspection Report 50-336/88-02, the inspector had not considered SP-2613C, Engineering Safety Feature (ESF) Integrated Test, successfully complete The initial start and subsequent restart of the facility II Emergency Diesel Generator (ECG) actuation time for the "C" charging pump for Sequence 2 was in excess of the allowable 8.4 seconds. The "C" charging pump started at 8.7 and 8.8 seconds, respectively. The inspec-ter reviewed the plant computer sequence of events and a video tape of control room panel CO-1 to verify the starting times of the "C" charging pum The actuation relay was tested prior to the Integrated Test and was re-corded on Instrument and Control (I&C) form 2403H-9. The relay was also tested subsequent to the Integrated Test on Work Order M2-88-02019. The inspector found that relay testing to be satisfcctory. No inadequacies were note On 2/9, the "C" charging pump was tested by the licensee using monthly

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surveillance procedure SP260lH. The charging pump start signals gene-rated via the Engineering Safety Actuation System (ESAS) test switch uses the same actuation module and relay as the Integrated Test. The test results were 0.144 and 0.131 seconds for the two starts. The licensee has committed to monitor the response time for the first four months of Cycle 9 power operation to verify proper operation of the "C" charging pum The inspector concluded no safety concern existed for the "C" charging pump start times, since an integral time limit of 28.4 seconds (EDG start, and "C" charging pump sequenced on the bus) is assumed for the design base accident conditions and was not exceeded. The inspector had no further questions.

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6.0 Temporary Instruction (TI) 2515/86 - Inspection of Licensee's Actions Taken to Implement Generic Letter 81-21, Naturaf Circulation Cooldown (25386)

Background While St. Lucie Unit I was cooling down under natural circulation on June 11, 1980, flashing of coolant produced a void in the reactor vessel upper head, forcing water into the pressurizer. The reactor was taken to cold shutdow Multi plant action item (MPA) F-66 was developed by the NRC to assure that all pressurized water reactors (PWRs) implement procedures and training pro-grams to deal with such events. NRC Generic Letter 81-21 asked licensees to assess their facility procedures and training program, including:

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Demonstrating (i.e., analysis / tests) that controlled natural circulation from operating conditions to cold shut down conditions, conducted in accordance with plant procedures, should not result in reactor vessel voidin Verifying that supplies of safety grade auxiliary feedwater are suffi-cient to support plant cooldown metl.od Describing plant training programs and emergency procedures that prevent or mitigate reactor vessel voidin TI 2515/86 provides guidance on satisfactory completion of licensee actions in response to MPA-B-66. Its provisions are addressed in the following, Identify Plant-Specific Requirements from the Licensee's Response to MPA-B-66 (Generic Letter 81-21)

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On October 20, 1983 an NRC safety evaluation was completed on natural

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circulation cooldown. This evaluation was based on the licensee's re-sponse to generic letter 81-21 dated November 19, 1981. The safety evaluation concluded that there is reasonable assurance that steam for-mation at the upper head of the reactor vessel will not occur during natural circulation. The conclusion was based on a Combustion Engineer-ing study (CE-NPSD-154, Natural Circulation Cooldown Task 430 Final Re-port) as it applies to Millstone Unit 2, and the existence of sufficient auxiliary feedwater to provide for plant cooldown. However, the licensee submittal (11/19/81) lacked information on the adequacy of training on natural circulation cooldown as it pertains to void formation and conse-quence, signs of voiding, disrussions of procedures to prevent or miti-gate voiding, discussions of the St. Lucie Event, and simalator modeling of upper head voidin The inspector reviewed training lesson plan M2-OP-RO-FUND-2121J (Reactor

, Coolant System Heat Removal). The lesson plan explains plant response

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from single phase natural circulation to two phase natural circulation,

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two phase natural circulation to reflux boiling, and the criteria used to determine the existence and adequacy of natural circulation. The inspector concluded that M2-0P-RO-FUND-2121J training lesson adequately explains voto formation and plant parameters utilized to determine void formation to control room operators. No inadequacies were foun In lesson plan R02-20(B), Natural Circulation Cooldown, Step C.5., void control in 6he RCS is discussed. The operators are taught fundamental methods of mitigating or diminishing the effects of voiding in the Reac-tor Coolant System (RCS). In ler. son plan M2-0P-R0-TA-2026 (Mitigating Core Damage) under Section VII, Msjor Industry Events, the St. Lucie Unit 1 event was described in detail. The instructor is provided guidance in this lesson plan to question control room operators on why parameters change and on the consequent operator actions. No inadequacies were noted in the application of training lesson plans R02-20B and M2-0P-RO-TA-202 The inspector reviewed Simulator Instructor's Guide R02-20(S), Natural Cir:ulation Cooldown. Simulator exercise R02-20(S) provides a scenario to operators for head bubble formation during a natural circulation

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cooldown. The inspector had no further questions in regards to this matte b. Verify That the Training program Inc.ludes Classroom and Simulator Cover-age of Natural Circulation Cooldown_ Procedures by Review of Records, Discussions with Individuals, or Obrervation

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of Similar Activities for Three Licensed Operators Results:

The inspector interviewed training department personnel to determine the program for natural circulation cooldow The program consists of the following; i) Classroom Phase - Lesson plan R'-0P-R0-FUND-2121J (RCS Heat Remo-val) - for fundamental training on heat transfer and thermodynamics for all licensed operator ii) Simulator Briefing Room - Lesson plan R02-20(B), Natural Circulation Cooldown. The lesson plan links fundamental concepts in the class-room and applies the concepts to Abnormal Operating Procedure (AOP)

2553, Natural Circulation cooldow iii) Simulator Phase - Lesson plan R02-20(S). This training provides hands-on simulator training on natural circ.ulation cooldown and the presence of RCS voids, i

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iv) Training Performance Guide (TPG) 2553 - This lesson plan appites to requalification of licensed operators. It provides a simulator exercise on natural circulation cooldown utilizing AOP 2553 and as- ,

sociated enabling objectives. The inspector reviewed training records on the most recent operator initial qualification and re-qualification to verify natural c!rculation training explained above was documented as being complete No inadequacies were note The inspector interviewed selected licensad operators in the control room concerning the indications of establishment of natural circulation and void formation in the RCS. No inadequacies were noted, Verify That the _ Licensee Has Emergency Procedures Regarding Natural Cir-culation - Specifically, Ensure that Proceduros for Reactor Vessel Upper Head Bubble Prevention or Mitigation are in Accordance with the Response to Generic Letter 81-21 Results:

Licensee Abnormal Operating Procedure (AOP) - 2553, "Plant Cooldown using -

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Natural Circulation" is utilized to cooldown the reactor from hot standby to shutdown cooling initiation using natural circulation. The entry conditions for this procedure are: reactor tripped; reactor coolant pumps not in operation; and natural circulation established in at least one loo No inadequacies were note The inspector reviewed the most recent initial operator qualification

"daily student task evaluation" records for R02-20(S) "Natural Circula-tion Cooldown." The student task evaluation was reviewed for content, t detail and student documentation of successful completion of the simula-tor exercise. No discrspancies were note !

An A0P-2553, Step 3.2 precaution provides two specific indications of

< reactor vessel head voiding for the operator, The indications are:

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Pressurizer level tricrease greater than expected while using auxiliary spra Pressurizer level decrease while operating charging pumps or high pressure safety injection (HPSI) pump Procedure step 4.11 of A0P 2553 direc+,s the operators to observe avail-able indications for void formation during depressurization. Volds may bs allowed to remain if the reactor coolant system is greater or equal to 30 degrees F subcooled and at least one steam generator is available for heat remova l

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If the above conditions cannot be satisfied, then operator actions under 4.11.c of A0P-2553 are relied upon to reduce or eliminate the voi The inspector had no further questions in regard to this are .0 Surveillance (61726)

On February 16, the inspector observed surveillance SP-21010 "Control Element Assembly (CEA) Drop Times". This procedure determines the full length CEA drop times (full out to 90% in 'rtion). The maximum drop time ptrmitted by

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Technical Specification 3.1.3.4 1 the assumed CEA drop time used in the ac-cident analysis. The acceptable drop time is less than or equal to 2.75 seconds. The inspector verified that prerequisites and initial conditions for portions of SP-21010 were satisfie Procedural adherence, granting of administrative approvals, test equipment in proper calibration, and conform-ance to technical specifications were note During the performance of $P-21010, CEA 5-4 drop time was 2.722 second This value was within the technical specific. tion limit, but in excess of the average rod drop times 2.3-2.4 seconds. A retest was required on rod 5-4 per step 7.2.26 of SP-21010. The licensee concluded that this drop time was at-tributed t.o rod bounce as indicated by the lower electric limit reed switch indication. The licensee's retest drop time was 2.371 seconds as recorded by the process computer. The inspector has no further questions in regard to this matte The inspector reviewed test data for accuracy and completeness. No unaccept-able conditions were identifie .0 Nechanical and Hydraulic Snubber Inspection (6172 In acco-dance with TS 3/4.7.8, hydraulic and mechanical snubbers were visually inspected and functionally tested during the 1938 refueling outage. All 134 mechanical and 147 hydraulic safety-related snubbers were inspected by a sub-contractor. Of these, 122 mechanical and 110 hydraulic snubbers passed with-out comment. Of the 12 mechanical and 37 hydraulic snubbers requiring further review, 2 mechanical and 8 hydraulic snubbers were determined to be acceptable-as-is by the assigned site engineer. The remaining 10 mechanical and 29 hydraulic snubbers required NUSCO engineering review and disposition. None of the visual snubber problems were considered failures by the license The inspector reviewed the various surv9illance procedures and the visual inspection data including the engirieering evaluations. In response to in-spector questions, the assigned sito engineer provided the following informa-tio * Reinspection data shcwing 3/16-inch hcles had been drilled 1/2-inch from the toe of the weld to the end attachment per disposition of Snubbers 416014A and . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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The individual reinspecting a snubber af ter correcting a deficiency is aware of the original proble * No work was done on the steam generator hydraulic snubbers this outag Inspection of these snubbers is due in 199 * The basis for accepting Snubbers 413021, 4130238, and 119R28A as "Accept-able-As-Is" for actual travel less than design was a known error in EP 2115 This error was correcte * The "Acceptable-As-Is" dispositions for Snubbers 40101B, 501022A, and 5130238 were revised to provide written justification for travel inter-ference * Snubber service life is verified, per TS requirements, since all snubbers were overhauled in 1985 and are, therefore, acceptable until 1990. All replacement snubbers are rebuilt prior to installatio For the bench testing rcquirement, the inspector reviewed the Snubber Test Selection List, the testing result packages, and the disposition of testing problem The 18 mechanical and 17 hydraulic snubbers (10% sample) selected for testing included different sizes of snubbers, and 4 mechanical and 2 hydraulic snubbers that had previously faile This is in accordance with TS 4.7.8.1.c. The licensee had devised a program to replace all snubbers to be tested with spare snubbers from the warehouse. These replacement snubbers were reworked and tested prior to installation. The advantages of this ap-prasch were: (1) reduced time of safety system inoperability; (2) improved control of snubber testing; (3) reduced radiation exposure due to single ac-cess of snubber replacement crews into radiation areat; and (4) improved out-age efficienc The inspector had no further question .0 Allegation RI-88-A-003, Excess Hours Worked at Millstone 2 (92720) l This allegation involves electricians working more than 16 hours straight, without prior authorization, in July 1987, during a Unit 2 outag The in-spector interviewed the alleger, the alleger's foreman, another involved electrician, and the Millstone 2 Superintendent. The controlling administra-tive procedure, ACP 1.19, Overtime Controls for Personnel Working at the Operating Station (NE01.09), which implements TS 6.2.2.g, provides guidelines on the length of the work-day (not over 16 hours straight or over 16 hours in any 24 hour period), rest time between days (no less than 8 hours between work pericas and no more than 24 hour > of work per any 48 hour period), and total hours worked per work week (no more than 72 hours).

The work being performed was the inspection and replacement of jumper wires in safety-related Motor-Operated Valves identified in an NRC inspection as not meeting Environmental Qualification requirements. The four people inter-

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viewed believed the MOV inspections and jumper wire replacements were completed correctl Post-removal inspection showed the jumper wires replaced were all Vulkene Supreme (the environmentally qualified type). The problem had been improper labeling, not incorrect wir TS 6.2.2.g. requires implementation of administrative procedures to control working hours of the staff who perform safety-related functions. This issue

was the subject of a previous violation in routine Inspection Report 50-336/ 87-29-01. No response by the licensee was required at that tim The inspector reviewed the Maintenance Department, I&C Department, and Engi-neering Department overtime records for thc recently completed Unit 2 outag From the posted total overtime listing in the Maintenar:ce Department, eight names were solicited and compared with all author:zatiers to exceed ov6rtime sheets and weekly time records for the outage. Twelve individual cases where approval was not obtained prior to exceeding the ACP 1.19 guidelines were identifie l The inspector interviewed first line supervisors in the maintenance department to determine the amount of interface occurring between the workers, the con-ditions utilized for granting overtime, and the capability of workers to work > excess hours especially on safety-related work. No inadequacies were foun [ The inspector will continue to pursue overtime controls from the previous outage, and review the licensee response to allegation RI-88-A-003, during the next routine inspection report. This item is open pending that further review (UNR 83-06-02).

10.0 Failure of "D" Reactor Coolant Pump (RCP) Seal (93702) At 8:20 p.m. on 2/13, during the plant initial heat-up from the Cycle 9 re-fueling outage, with reactor coolant system (RCS) temperature at 455 degrees F and RCS pressure at 1500 PSI, the "D" reactor coolant pump (RCP) seal high bleedoff flos temperature alarm occurred at 175 degrees F. The licensee secured the "D RCP at 10:17 p.m. and commenced cooldown for repair ' On 2/15, the licensee replaced the failed seal per procedure MP-2703E6B, RCP Seal Removal and Installation. The inspector reviewed pre-installation test and overhaul procedures M2-87-13179 and M2-87-13179 for the failed seal, No ir, adequacies were noted. The inspector also reviewed M2-88-2342, Pre-instal-lation Test, for the replacement stal. This procedure determines control bleed-off flow, breakdown pressurr. indications, and general overhaul of the seal in a test fixture assembly.

! On 3/4, a licensee critique concluded that the cause of failure of the "0" ' PCP seal was improper installation during the outage. Specifically, the ad-justing cap was adjusted incorrectly and the locating pins from the upper pressure breakdown device were removed prematurely. These actions resulted in pre-stress to the shaft seal, causing shaft to seal misalignment and high

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Licensee procedure MP-2703E60 addresses removal and installation of a RCP seal with the motor removed. According to the licenseo, shaft seal replacement normally occurs with the RCP motor aligned with the associated pump; however, during the refueling outage, the "0" RCP motor was removed and replace During installation of the RCP seal, an inadequate turnover by maintenance personnel and miscommunications regarding the final steps of installation of the seal occurred. MP-2703E6B, RCP Seal Removal and Installation (with the RCP motor installed), was use The inspector asked how the wrong procedure was used for final completion of the seal installation. The licensee re-sponded that procedure MP-2703E6B is normally found in the RCP seal replace-ment tool box. The licensee specifically provided a new seal replacement tool box with the correct procedure, MP-2703E60, for the outage. However, in the job-site turnover process, the incorrect tool box and procedure were use The licensec's critique identified the following actions: face-to-face job site turnover; no procedures in the tool boxes; specific seal alignment training on the seal mock-up; having the same work crew work on the procedure; and quality control hold points in MP-2703E60 and MP-2703E6B to verify ad-justing cap and locating pin positions. The inspector had no further ques-tion . 11.0 On-Site Plant Operations Review Committee (PORC) (40700) ' The inspector attended Unit 2 PORC meetings on February 9, 12, 16, 19 and March 1 Tachnical Specification 6.5.1.2 requirements for committee compo-sition were met. PORC topics and review included the following:

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Plant Design Change Record (PDCR) M2-88-014, "Terry Turbine Drain Line ' Hanger Modification." This change installs a simple hanger to organize and support various lines emptying into the Terry Turbine room sum MP 2708A, "Electrical Valve Operator Repairs" Revision 10, Change This procedural change permits adjustment of the torque spring assembly when additional assembly guic'ance is availabl l

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I&C Form 24360-1, "Safety Related Instrument Start-up Valve Lineup Data Sheet." This change reflects revised instrument valve configurations due to modifications during Cycle 9 refueling outag OP 2387G, "Inadequate Core Cooling System." This change was made to direct operators to open the door connecting the new and old computer rooms and station a fire watch during periods of extended Loss of Normal Power (LNP) operation This change was made to incorporate changes made in PDCR 2-4-83, Old Computer Room HVAC Mod SP 2674, "Pressurizer Spray Line Bypass Valve Adjustment." This proce-dure incorporates inservice test guidance into an Operations procedur The PORC concluded this does not constitute an unreviewed safety question

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  . PORC-commitment 88-3 was initiated to ensure SP 21010 is revised to pro-vide sufficient boron concentration to maintain shutdown margin when withdrawing more than 1 control element assembly (when using.the plant process computer for CEA drop time tests).

No deficiencies in'PORC performance were observe .0 Review of Periodic (90713) and Special Reports (92700) Upon receipt, periodic and special reports submitted pursuant to Technical Specifications were reviewed. The review verified that the reported informa-tion was valid and include required NRC data. The inspector also reviewed whether any reported information should be classified as an abnormal occur-rence. The following reports were reviewed:

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Monthly Operating Report (88-01) for January 1988

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Monthly Operating Report (88-02) for February 198 ,

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Special Report submitted in accordance with Technical Specification 4.4.5.1. This special report detailed the results of the in-service  ; steam generator tube inspections. As a result of the inspection both steam generators were in Technical Specification 4.4.5.1.2.c, Category C-3 which required the licensee to submit a special report prior to re~ i sumption of plant operations, and provide a description of investigations ' conducted to determine the cause of tube degradation and corrective actions to prevent recurrer.c No deficiencies were noted during these review . Management Meetings (30703) At periodic intervals during this inspection, meetings were held with senior plant management to discuss the finding No proprietary information was identified as being in the inspection coverag No written matecial was pro-vided to th" licensee by the inspecto _ }}