IR 05000245/1989008
| ML20245E122 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 06/15/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245E094 | List: |
| References | |
| 50-245-89-08, 50-245-89-8, NUDOCS 8906270331 | |
| Download: ML20245E122 (29) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /89-08 3 l Docket N License N DPR-21 Licensee: Northeast Nuclear Energy Company ) Facility: _M_illstone Nuclear Power Station, Unit 1 _ Inspection At: Waterford, Connecticut Dates: March 28 through May 8, 1989 j Inspectors: Scott Barber, Millstone 3 Resident Inspector , Paul Kaufman, Project Engineer, DRP Section IB ( Lynn Kolonauski, Resident Inspector, MP-1 l William Raymond, Senior Resident Inspector Theodore Rebelowski, Senior Reactor Engineer, DRS Carl Woodard Reactor Engineer, DRS Approved by: E. C. McCabgf, Ch
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, React 6F Projects Section IB
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Inspection Summary: Inspection from March 28 to May 8, 1989 (Report 50-245/89-08) Areas Inspected: Previously identified items, plant operations, phys'ical secur-ity, licensee receipt inspection of new fuel, refueling; plant modifications including the Spent Fuel Pool Rerack project, the ECCS Torus Suction Strainer replacement, and the GTG governor replacement; maintenance and surveillance, i licensee event reports, and committee activitie The inspection involved 304 inspection hours, including fifty six (56) back-shift hours, of which twenty-two (22) were deep backshift hour J Results: The inspection identified no unsafe plant conditions, Two licensee-identified safety system inadequacies required further inspector follow-up (De-tails 4.1, 8.2). Unresolved items were identified on the Millstone procurement ; and material storage control program (Detail 3.2), the secondary containment 1 test results associated with the standby gas treatment system inoperability during irradiated fuel movement (Detail 4.1), the Spent Fuel Pool Boraflex sur- , veillance program (Detail 7.1), and the 1-CV-2 weld repair plan submitted to ' NRC:NRR (Detail 8.1).
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TABLE OF CONTENTS PAGE 1.0 Persons Contacted.................... ............................... 1 2.0 Summary of Facility Activities.............. ........................ 1 3.0 Status of Previous Inspection Findings (93702/71707). .. . . . . . . . . . . . . . . . 2~ 3.1' (Closed) IFI 85-10-01, " Gas Turbine Generator Air Start Valve Failures"... ................................................. 2 3.2 (Closed) UNR 88-17-03, . "Nonqualified Charcoal Filters Installed in Standby Gas Treatment System".............................. 2 3.3 (Closed) UNR 88-25-03, " Loud Main Control Room Printers"........ 3 4.0 Facility Tours and Operational Status Reviews (71707/71710/93702).... 4 i 4.1 Safety System Operability....................... ............... 5 4.2 Review of Plant Inc.ident Reports.................... ..... ..... 7 4.3 Significant Operational Events.................................. 8 4.4 Review of Radiological Controls.... ............................ 10 4.5 Availability of ECCS Systems During Bus Inspections....... ... . 10 5.0 New Fuel Receipt Inspection (71707)....... .............. ........... 12 6.0 Refueling Activities and In-Vessel Work (71707/62703)................ 13 7.0 Plant Modifications (37700/37828).................................... 14' 7.1 Spent Fuel Pool Rerack Project.................................. 14 , 7.2 Emergency Core Cooling System (ECCS) Suction Strainer i Replacement................................................... 17 7.3 Gas Turbine Generator (GTG) Governor Replacement. . . . . . . . . . . . . . . . 18
8.0 Maintenance (62703)................................................... 23 8.1 Reactor Water Cleanup (RWCU) Valve 1-CU-2 Weld Repair........... 23 8.2 Standby Liquid Control (SLC) Explosive Assembly Replacement. . . .. 24
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9. 0 Surveillance (61726)................................................. 25 10. 0 Li cen see Event Report s ( 92700) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 11.0 Plant Operations Review Committee (40500)............................ 25 12.0 Management Meetings (30703).......................................... 26 i
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DETAILS 1.0 Persons Contacted J. Stetz, Unit 1 Superintendent R. Palmieri, Operations Supervisor P. Prezkop, Instrumentation and Controls Supervisor N. Bergh, Maintenance Supervisor W. Vogel, Engineering Supervisor M. Brennan, Health Physics Supervisor The inspectors also contacted other members of the Operations, Instrumen-tation and Control, Maintenance, Engineering, and Health Physics depart-ment .0 Summary of Facility Activities Millstone 1 operated at full power for the first half of this report period with the exception of short power reductions for routine surveil-lance. On April 7, while conducting a normal shutdown for the Cycle 12 refueling outage, the unit scrammed from 80% power due to a turbine trip generated by an erroneous high level signal from the "A" moisture separa-tor (Detail 4.3). Cold shutdown conditions were attained on April 8 and were maintained for the rest of the inspection perio Major refueling outage activities conducted during the period included:
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The degraded grid /underveltage protection inputs were relocated to the 4 KV Class IE buses, upgrading Millstone 1 bus protection per NRC Branch Technical Position (BTP) PSB- Environmentally qualified motor-operators were installed on the low pressure coolant injection (LPCI) containment spray valves (1-LP-15A/B and 1-LP-16A/B) and reactor water cleanup (RWCU) suction isola-tion valves (1-CU-2 and 3).
-- The electro-hydraulic gas turbine generator (GTG) governor control system was replaced with microprocessor-based hardwar Emergency core cooling (ECCS) torus suction strainers with greater surface area were installed to reduce the possibility of ECCS pump head loss due to fibrous insulation clogging during post-accident conditions.
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The core was completely off-loeded into the Spent Fuel Pool for in-vessel ISI (inservice inspection). The Cycle 13 core contains 196 new GE8B fuel assemblies, six new local power range monitors (LPRMs) with GE NA300 detectors, and 35 replacement control rod I _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ J
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The rebuilt main transformer was reinstalled,' replacing the spare' , transformer-that had been in service throughout. Cycle 1 ;j
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Four. motor-operated containment... isolation. valves on. Reactor, Building
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Closed Cooling Water (RBCCW);were.' installed in response'to a licensee- , finding described in~NRC. Inspection Report (IR);50-245/89-04. Detail l feismic supports were installed on non-safety 4KV bus'14D in response: to a.recent licensee finding that its collapse during a. severe earth-quake could cause a loss of AC power at Millstone 1 due to the effect : on'other bus duct During the Cycle 11 refueling outage, the licensee had planned to l
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change out control rod 26 43, but could not. uncouple it from its
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drive mechanism. The rod remained in service'during Cycle 12. After
~ .several unsuccessful unlatching attempts during the current outage, maintenance personnel freed the rod by cutting its piston tube from under the vessel using specially fabricated toolin l 3.0 Status of Previous Inspection Findings 3.1 (Closed) IFI 85-10-01, Gas Turbine Generator (GTG) Air Start Valve .l Failure i The GTG failed to start during an April 1985 surveillance due to an inoperable air start valve. The licensee replaced the valve and the GTG was retested satisfactorily. As' reported in NRC IR 50-245/87-05, the valve manufacturer, AiResearch Corporation, has. failed to provide a root cause failure analysis in spite of numerous. licensee request The licensee had previously attributed several failures to rust foul :
ing in the air supply. The GTG air receiver discharge piping to the air start valves was converted from carbon steel to stainless steel in 1982. Piping from the air compressor to the air receiver is~ still
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carbon steel. The licensee developed associated Plant Design Change Record (PDCR) 1-14-88 but, due to schedule constraints,:implementa-s tion during the current outage appears unlikel No similar failures have occurred since April 1985. The licensee's PDCR system will track completion of further air supply. improvement This item is close .2 (Closed) UNR 88-17-03,' Installation of Nonqualified Charcoal Filters in the Standby Gas Treatment System (SGiS) On September 23, 1988, the licensee installed nonqualified charcoal (ordered in 1981) in the SGTS. Further inspector review confirmed that both storeroom and maintenance personnel failed to recognize
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that the charcoal was without green tags, which the licensee.use's to-indicate qualified material. After the event, the licensee briefed-storeroom and maintenance personnel on.materialiissue form (MIF) com-pliance,. removed all'nonqualified charcoal filters from the store-
. room,'and cancelled the repeating requisition for,nonqualified:fil-- j ters. A maintenance engineer; discovered additional: nonqualified fil-
-ters in;the' Great Neck warehouse and initiated automated work orde '
(AWO)~M1-89-01634' for their disposal after the outage; the installed- 1
' filters are notischeduled for replacement until September 1989. In-addition,. OPS Form 646.5-1, "SGTS Charcoal Absorption Test,"'now re- '
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quire's the Material Receipt' Inspection Re' port (MRIR) number for~the' 1 certified charcoal filters cells to be recorded and a copy; of'the: vendor's charcoal efficiency report to'be attached. The. inspector
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concluded that these measures -were sufficient to' preclude' recurrenc and this specific-issue is close Several issues involving the licensee's stock control program remain unresolved. -The' program-discussed in administrative control proce- 3 dure (ACP) QA-4.06A,'" Establishing Control of In-Stock Degradable Material," Revision 2 encompasses 32,435 items coded in stock. _The -{ licensee recently identified almost 24,000 in stockLitems that were not coded with expiration date information. ' Continued licensee ef-fort is needed to reduce the nunber of ' unidentified item Station procedure STP 1705 addresses the shelf life program including procurement, receipt inspection, handling and tracking. methods. It requires frequent review to update-the generic degradable items list based on the coding of in-stock items. As of March 9, 1989, the lic-ensee had identified 7950 degradable items, 4093 degradable assem-blies, and 1006 non-stock coded item The licensee is planning to upgrade ACP-QA-4.04, " Instructions for Packaging, Shipping, Storage and Handling," which controls the mate-rials issued from the warehouse to maine.enance personnel. Actions f l include the removal of items that are overstocked or obsolete due to ' plant design changes. The inspector toured the onsite and offsite warehouse facilities, where more than 100' pallets contained material
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ready for sale ~at various licensee auctions. The consolidation of warehousing, along with the reduction-in coded in-stock items, .will help in controlling the degradable materials progra The licensee has initiated additional training 'for stock handlers and - maintenance personnel in material identification and the use of' mate-rial issue forms. Additionally, discussions with licensee management indicated that changes contemplated in the service organization in-clude the development of a new material control' grou : l i
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No outdated material use was identified. However, adequacy of de-gradable material shelf life controls is unresolved pending the planned development and implementation of the revised procedures and i training plans, and subsequent NRC program review (UNR 50-245/89-08-01).
3.3 (Closed) UNR 88-25-03, Loud Main Control Room Printers While observing licensed operator requalification examinations at the Millstone 1 simulator in December 1988, the inspector noted that the two Digital LXY22 printers were so loud that they inhibited shift communications. The printers are located in front of the emergency core cooling panel and provide the Balance of Plant and Nuclear Steam Supply System outputs. These logs are generally not used by opera-tors but by plant management during post-trip reviews. The licensee originally planned to build sound enclosures for the printers but determined.that the problem could be more easily resolved by redirect-ing the post-trip and scram logs to the computer room, which is lo-cated below the main control room. That action was taken, and the control room is quieter. Alarm log and sequence of events (SOE) printouts are still available in the control room for operator use in plant transient response. This item is close .0 Facility Tours and Operational Status Reviews The inspector reviewed control room indications for proper functioning, correlation betweer channels, and conformance with Technical Specifica-tions (TSs). The inspector verified proper control room manning and dis-cussed alarm conditions in effect and alarms received with the operators and found them to be cognizant of plant conditions and indications. The inspector observed prompt and appropriate operator response to changes in plant condition Operator logs and Plant Incident Reports (PIRs) were reviewed for accuracy and adherence to station procedures and TSs. The inspectors also verified proper implementation of selected aspects of the station security program, including site access controls, personnel searches, compensatory measures, adequacy of physical barriers, and guard force response to alarms and de-graded conditions. No inadequacies were identifie Plant housekeeping controls in all areas toured were observed, including control of flammable and other hazardous materials. Housekeeping condi-tions in the drywell were reviewed during tours on May 4. Housekeeping was found acceptable for the work activities in progres The inspector reviewed the adequacy of licensee controls for system tag-outs during drywell inspection Tags hung for the "B" recirculation pump (tag order 89-593) and the 1-FW-1B feedwater block valves (orders 89-820 and 89-907) were reviewed on a sampling basis for proper tag placement, valve positioning, and updated tag index status. The implementation and _ _ _ _ _ - _ -_-
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1 restoration of bypass jumper 1-89-9 for the diesel generator was also re-viewe (See Detail 4.1 for inspector follow-up of' errors in conducting tagging order 1-1084-89.) The inspector had no further question ; i-The' inspectors conducted backshift' inspections of the control room.and found all. shift personnel to be alert and attentive to their duties'. : No unacceptable' conditions were identified. The inspectors also addressed the_following activitie .1 Safety System Operability Prior to the unit shutdown for refueling, the inspectors reviewed the . . following standby emergency systems to. determine operability and readiness for automatic. initiation: feedwater coolant injection, I i automatic pressure relief,. low pressure coolant inject _ ion, emergency _ service water, core spray, standby gas treatment, standby liquid' con-trol, and pr % ry containment. The status of the control rod drive hydraulic control- units, emergency diesel: generator, gas turbine, station batteries, and isolation condenser was also inspected. The reviews considered proper positioning of major flow path valves, operable normal and emergency power sources, proper operation of in-dications and controls,-and proper cooling and lubrication. Refer- ! ences used for the review included the Updated Final Safety Analysis Report, and system diagrams and operating procedures. During_the-refueling outage, the inspectors verified licensee compliance with- l appropriate technical specifications,. including those for mode switch position, minimum neutron monitoring instrumentation, and spent fuel
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i pool and shutdown cooling. The inspectors identified no inadequa- I cies. Two licensee-identified inadequacies 'are described belo ' 4. Core Spray System Flanges The licensee conducted hydrostatic testing of the Class 2 portion of the core spray (CS) system per the Ten Year In- ! Service Inspection (ISI) program. During a four hour May 2 ) test of the "B" core spray (CS) system at 469 psig, the licensee noted minor leakage from restricting orifice R0 10-2B, located downstream of the "B" CS pump discharge
. check valve. No leakage was identified during the "A" CS hydrostatic test, and both Cb systems passed their respec-tive test In removing the insulation from R0-10-28 in the expectation of repairing the leak by replacing the l flexatallic gasket, the test engineer noted that the "B" i flanges associated with R0 10-2B had a Class 150 rating !
inscribed on them. The CS system pipino_ design rating i J 350 psig. The licensee determined that the underrated I flanges had been present in the system since original con-struction, and had passed original hydrostatic testing at
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525 psig. The licensee replaced the flanges with fully rated ones and the system was retested satisfactorily. The
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inspector observed the . replacement flanges and verified the flange ~ rating per ANSI B16.5 by two separate methods: the' inscription (10-300-B16 STD SA105 4AGJ USA) and.the bolt configuration (sixteen one-inch bolts). Per ANSI B16.5, i! ten-inch diameter, Class 300 carbon steel . flanges can with -; J stand the CS system design pressure (350 psig) to a_ tempera-' ; ture of 800 F. The inspector found the replacement.to be acceptable, noting that CS system. design temperature' is 350 .
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F. T_he licensee plans to report'the event per 10'CFR 50.73- I a(2)(v) and 10 CFR 50.73 a(2)(vi). The licensee inspscted all core spray system flanges and identified no additional' underrated flanges. The inspector had no further ques-tion . Standby Gas Treatment System Inoperable During Irradiated Fuel Movement On May 2, at 8:30 a.m., the licensee removed the "A" stand- .!'a by gas treatment system (SGTS) from service for environ-mental equipment qualification-(EEQ) upgrades'. When the licensee attempted toLdemonstrate that the inservice train ("B") was operable per TS 3.7.B.3 on May 3..at 9:10 a.m., the inlet flow meter indicated lower than usual. Sinc SGTS is required for secondary containment integrity during i irradiated fuel movement, the licensee' immediately . sus-pended core reload operations. After. verifying that the flow instrumentation was' operable, the licensee discovered that a tagging error had left.the "A" SGTS inlet and outlet dampers (1-SG-2A and 4A) open,' setting up a recirculation /. 'l bypass flow path through the "A" SGTS train when the "B" l SGTS train was placed in service. The licensee'had iso- i lated the air supply to 1-SG-2A and 4A per the tagout (.1-1084-89), not recognizing that the valves failed open on l 1 loss of air. Preliminary licensee evaluations'. concluded i that the degraded SGTS condition'would still-provide lsome -l negative reactor building pressure (approximately 0.17" j WG), but could not conclude that the 0.25" WG criterion of TS 4.7.C.1.a could be met. The-licensee reported the event' j per 10 CFR 50.72 (b)(2)(iii) and resumed core reload after
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closing the manual "A" SGTS blower inlet damper (1-SG-3A), adding it to the tagout, and conducting a. satisfactory re-test of the "B" SGT t
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The licensee plans another secondary containment tightness test under the same degraded SGTS conditions to determine ; if sufficient negative pressure could be obtained in the ! reactor building. Failure to have SGTS. fully ope'rable dur- , ing irradiated fuel movement is.not'in accordance with TS: 1 this issue is unresolved pending the secondary containment- 1 test results (UNR 89-08-02). I
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- Plant Incident Reports-Shiected plant incident reports (PIRs) were ' reviewed to (1) determine the significance of the events,'(ii) review the. licensee's evaluation'
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of the events,.(iii) verify the ' licensee's response and corrective actions, and (iv) verify whether the licensee reported'the. events in acco'rdance with applicable-requirements. Significant. events are de-scribed below or elsewhere in this report as referenced. The fol-lowing PIRs were reviewed: 1-89-18(Detail 10.0), 1-89-20 (Detail 4.3), 1-89-24, 1-89-26, 1-89-27 (Detail 8.1), 1-89-31, 1-89-32 (De-tail 4.3), 1-89-33, 1-89-34:(Detail 4.2), 1-89-35 (Detail 4.2)! No
' inadequacies were : identified i Millstone 1 TS.3.6.D limits primary system boundary leakage 'to gpm from unidentified sources and 25 gpm total from identified and unidentified sources when irradiated fuel is in the reactor pressure vessel (RPV). If TS 3.6.D'cannot be met, the reactor must be in cold shutdown within 24 hours. Associated TS 4.6.D requires that the reactor coolant ~ system leakage rate'into primary containment be de -
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termined daily. This is implemented by associated station procedure l (SP) 635.1, " Reactor Coolant Sys. tem Leakage. Check," which requires l' the drywell equipment and floor drain sump leakage rates to be. deter- .i mined every four hours. PIR-1-89-31. documents the licensee's failure to follow SP 635.1 upon entrance in to.the refueling mode; Operations suspended the surveillance during cold shutdown in order to keep the drywell sumps full, thus providing shielding to minimize radiation exposure to drywell workers. .Because the Millstone l'TS define oper-ating mode by the mode switch position, the licensee was in violation of TS 3.6.D from the time the reactor mode switch went from cold shut-down to " refuel" at 12:20 a.m. on April 15, until 10:00 a.m. on April 16 when the licensee discovered the oversight.and conducted the sur-veillance. The licensee then implemented interim change 1 to SP ' 635.1, Revision 10,-to specify that the surveillance need not be per - formed in cold shutdown with the mode switch in either " shutdown" or
" refuel" and plans a TS amendment request to this effect. The cold shutdown and refueling modes are much the same except for refueling provisions (cavity flooding, head removal, etc.). Also, cavity flood-ing before going from cold shutdown to refueling adds to the primary water inventory, provides level management, and adds a spent fuel pool level alarm to warn of leakage problems. Therefcre, determining the sump pumpout rate to determine leakage during refueling has. mini-mal safety significance. Further, the shielding provided by keeping the sumps full reduces the radiation hazard in containment. Nonethe-less, literal TS compliance is required, and TS changes need to be made before procedures are changed in such a way that compliance with an existing TS is no longer assured. Evaluation of the timeliness and acceptability of the licensee's corrective actions is being per-formed, hence this item remains unresolved (UNR 89-08-03).
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4.3 Significant Operation'al Events l l l Reactor Scram Generated by Turbine Trip l At 12:38 p.m. on April 7,' Millstone 1 scrammed from 80% power due to a turbine trip generated by an erroneous high moisture separator (MS)
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level- signal. Normal-reactor water level decrease 'during the scram
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l caused a Group 2 iselation and initiated the standby gas treatmen '! . system. No other emergency core cooling systems or engineered safety i L features actuated and all safety systems. responded normally. The i licensee stabilized the plant at hot shutdown and reported the event-
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( Just before the scram,t .lstone I was conducting a normal shutdown ] to begin the Cycle 12 refueling outage. Licensee investigation de- { termined that MS' level was low because the moisture' separator drain ! tank- (MSDT) normal. drain valve (1-HD-178)'was_ binding in .the . closed .I direction. Low MS le' vel introduced high pressure (HP) turbine ex- .! haust steam to the MSDT drain line, causing severe vibration and trip- j ping of the MS high level switch. This' caused the turbine trip and i resulting reactor scram. The licensee plans to rebuild the normal drain valve during the outag ,
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The inspector learned that the licensee had already planned to change ! the MS level logic from the current one-out-of-one configuration to ' prevent unnecessary scrams. Actuation of the new logic will require high MS level and either high.MSDT level or no low MSDT leve In reviewing the event, the inspector noted that the control room sequence of events (SOE) printout did not list some of the alarms in proper sequence. For example, turbine stop valve closure was listed- i as occurring 12 msec after the first reactor protection system (RPS) tri The inspector discussed this apparent discrepancy with the licensee, who conducted testing to determine the cause. First, the licensee tied several process computer inputs to,a single switch, and then changed the state of the switch to simulate simultaneous actu- : ation of the computer points. The SOE performed successfully, print- ! ing all points within the time range'specified by original process I computer design criteria. With the process computer /SOE interface functioning satisfactorily, the licensee postulated that the discre-i
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pancy could be caused by the timing difference between normally closed (NC) and normally open-(NO) contact inputs to the compute The licensee tested typical.GE HFA relays' and determined that, due to j the difference in travel time, a NO. contact. takes 20 msec longer to i close than it takes to open an NC contact. This is' consistent with j the turbine trip /RPS logic sequence experienced. The inspector had j
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At 5:00 p.m., with the reactor in hot shutdown at 515F and 866 psig, the unidentified leakage rate into the drywell increased to 2.69 gpm, exceeding the 2.5 gpm limit specified by TS limiting condition for operation (LCO) 3.6.D. The licensee declared an Unusual Event (UE) per their Emergency Plan Implementing Procedure (EPIP)'and. reported l the event per 10 CFR 50.72 (a)(2)(1)(B). At 7:00 p.m., with an RPV pressure of 400 psig, the unidentified leakage rate dropped to 1.88 gpm. At 7:08 p.m., the licensee exited the LCO and cancelled the U Once the oxygen concentration exceeded 20's, the licensee entered the drywell (at an RPV pressure of 300 psig) and discovered the leakage source was blown packing on 1-MS-5, a main steam drain line isolation valve. The licensee continued to cool down, and reached cold shut-down at 12:35 p.m. on April 8. 1-MS-5 will be repacked during the outage. The inspector identified no ' inadequacies in the licensee's response to the even Actuation of Loss of Normal Power On April 29 at 5:16 a.m., while'in cold shutdown, Millstone 1 experi- l
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enced a Loss of Normal Power (LNP) due to an undervoltage (UV) signal on the high side of the Reserve Station Services Transformer (RSST).
I Plant equipment responded as designed with the emergency diesel gene- { rator (EDG) automatically starting and supplying AC power to bus 14 j The gas turbine generator was out of service for governor modifica-tions. Operations provided power to buses 14C and 14E through the Emergency Station Services Transformer (ESST). At the time of the event, the licensee was removing the RSST from service for scheduled maintenance and was supplying unit AC loads by backfeeding through . the Normal Station Services Transformer (NSST). 1 The licensee was implementing the " Degraded Grid Protection for Class I 1E Power Systems" modification during the outage and determined that l an installation oversight allowed an unintended overlap between the ; original and modified UV schemes. Specifically, the licensee trans-l ferred a contact from an RSST UV auxiliary relay (92X2/STA) to the ) l ' modified UV scheme, not realizing that the coil remained in the RSST , UV scheme. When the RSST was deenergized, the new UV scheme initi- ! ated. The inspector noted that this relay coil and its contacts ap-peared on separate prints with two separate identification number j The licensee later placed the relay coil in the modified UV scheme
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only, per desig Since the core was off-loaded into the spent fuel pool, the signi- ! ficant AC load was Fuel Pool Cooling, which was restored within four minutes. The operators secured the EDG by 5:50 a.m. and restored the normal electrical lineup. The inspector reviewed the licensee's ac-tions and noted no unsafe conditions.
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4.4 Review of Radiological Controls During plant tours, posting, control, and the use of personnel moni-toring devices for radiation, contamination, and high radiation areas were inspected. Health Physics (HP) controls for work activities in the reactor building and in the drywell were reviewed during routine inspection tour This review was completed in detail for work ac-tivities under radiation work permits (RWPs) 741, 874, 786 and 972 in progress on the refueling floor and in the drywell on April 27 and ) May 4, respectivel The. inspector conducted independent drywell area dose rate measure-ments using licensee survey meters to verify proper posting of radi- { ation and high radiation areas, and reviewed RWP requirements to as- ' sure controls were appropriate and were based on recent survey in-formation. HP technician staffing and supervision was acceptable and personnel were following RWP requirements. In addition, the inspec- , tor interviewed several HP technicians to verify that they were knowl- J edgeable of their responsibilities and the work activities in pro-gress, that workers were briefed on the RWP requirements and measures { to keep exposures as low as reasonably achievable (ALARA), and that worker doses were tracked to assure administrative and regulatory limits were not exceede )< The inspector found good radiation protection controls and thorough ' supervision of technician ar.d worker activities. No inadequacies were identifie i 4.5 Availability of ECCS Systems During Bus Inspections l Planned work during the April 1989 refueling outage included insula-tion cracking inspections of 4KV buses 14C and 140. The buses would be deenergized one at at time, interrupting the normal supply to their respective downstream safety-related buses 14E and 14F. These bus inspections affected power availability to Class IE 4KV buses and associated engineered safety feature (ESF) equipment at a time con-current with core offloa ! In reviewing TS 3.5.F.7, the licensee recognized a problem in apply-ing operability requirements for ESF equipment in view of TS The licensee submitted a technical specification change request (later approved) by letter dated January 24, 1989 to clarify elec-
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trical supply separation requirements and specifically require that power be available to only one of the two ESF buse Per the licensee bus inspection plan, bus 14E (or 14F) would be de- i energized for the 14C (or 14 D) outage and the ESF pump breakers I would be racked down. Manual restoration would be required at both the control room (to energize the bus) and the switchgear (to ener-gize pumps). With offsite power available, 480V loads on 12E and 12F ,!
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would be cross-tied, impacting the independence and separation of the l Standby Gas Treatment system (SGTS). The inspector-noted, however, l that separation could be provided at any time by' operator action with j or without offsite power to assure at least one SGTS train was able to perform its intended functio i The inspector reviewed the issue with site personnel and with cor- i porate engineering personnel during a meeting on March 30. This re- j view included consideration of the electrical protection schemes on 1 the 4KV and 480V electrical systems, the adequacy of the 4KV to 480V . i transformers, and the assumptions used in the analyzed accidents de- l scribed in the FSAR. The inspector also noted that the NRC:NRR tech- 1 nical staff had accepted the licensee's proposed-technical specifi- 3 cation change request and that staff approval was expected to be l granted later in the outag .l The inspector concluded the existing TS 3.5.F.7 could be met if the i licensee proceduralized his method for implementation and assured that the operators were trained on the requirements. The licensee provided this instruction to the operators by incorporating a change to Special Procedure SP 89-1-28 as a definition of TS 3.5.F.7 ESF operabilit The inspector reviewed the special procedure and noted that it provided normal electrical system alignment during bus work ) and specified operator actions for loss of offsite power and for an i accident concurrent with a loss of offsite power. The inspector l found the procedure and the licensee's approach to be adequate based I on the following: ,
(1) no single failure could prevent use of at least one safety sys- ,
tem (i.e., ESF pump or SGTS) to mitigate events; !
(2) there is redundancy in the 345KV supply from.the reserve station services transformer (RSST) and a backup 4KV supply provided from the emergency station services transformer (27KV/4KV ESST)
and the emergency diesel generator; (3) the TS 3.5.F.7 requirements (2 ECCS pumps) are conservative com-pared to standard technical specifications which require only one ECCS pump to be available during refueling; (4) licensee calculations showed that, with the assumed manual ac-tions, operators could provide core injection in much less than j the two hour core uncovery time calculated for a drain down ' event; and, (5) the safety significance and risk would be minimal due to the low probability of a loss of offsite power and concurrent accident or electrical failur i
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. ,. .. .. , ~ 12 The licensee instituted a jumper request (1-89-9) to cause the emer-gency diesel generator (EDG) to preferentially power the 14E bus if required during the 14C bus outage. That provide a source of emer-
gency power to the LPCI and core spray trains de-energized as a re-sult of the 14C bus outage. (The EDG normally provides power to the 14F bus.) The inspector reviewed the licensee's safety evaluation for the jumper dated April 10 and identified no inadequacies. During review of the proposed interim electrical scheme, the inspector noted that, since the diesel tie breaker to Bus 14E was not subjected to periodic monthly testing (and should not have been for the normal electrical alignment), it should be tested prior to reliance on its auto close feature. The licensee acknowledged the inspector's com-ments and performed a test to verify satisfactory operation of the tie breaker's auto close feature as a prerequisite to operation under SP 89-1-2 The inspector reviewed plant operations during bus inspections and refueling activities and noted that the requirements of TS 3.5. and SP 89-1-28 were met. The bus inspections were completed and the normal bus electrical alignment was restored by April 28. NRC:NRR approved the licensee's revision to TS 3.5.F.7 in Amendment No. 31 dated May 5, 1989. The inspector had no further question .0 New Fuel Receipt Inspection On March 28, the inspector observed new fuel receipt inspection conducted by the licensee on Reload 12 fuel assemblies (FA) LSY145 and LSY152 per automated work order (AWO) M1890063 The inspector verified that the tasks, including movement to the new fuel inspection stand, inspection, j channeling, and storage in the new fuel vault, were accomplished in ac- { cordance with RE 1012, "New Fuel Receipt and Inspection," and the Quality j Services Department (QSD) inspection plan documented in SF 207A. The in- 1 spector verified that appropriate radiation protection controls were fol-lowed and that licensee inspectors were knowledgeable of their responsi- ! bilitie No inadequacies were note Although water rod length is not included in routine fuel receipt inspec- l tion, the licensee noted an apparent difference in water rod length during j inspection of FA LSY207 on March 16. Due to a manufacturing error, water j rod 21610 barely protruded above the FA upper tie plate (approximately 1 0.010" vs. 0.148"). The licensee inspected all Reload 12 FAs that were l- not inspected for short water rods at the GE fuel plant in Wilmington, NC using a specially fabricated "go-no go" gauge and discovered no additional '
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short water rods. The inspector observed the onsite inspections and dis- ; assembly and reassembly of FA LSY207 by a General Electric (GE) represen- i tative. The inspector verified that continuous support was supplied for ' the full length of FA LSY207 while it was reworked in a horizontal posi- ! tion. No inadequacies were identified in either the new fuel receipt in- i spection or water rod replacemen l
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60 Refueling Activities and In-Vessel Work Refueling activities were reviewed during the inspection period to verify that licensee administrative procedures and controls met regulatory. re-quirements, and that activities were implemented in accordance with ad-ministrative controls and were completed safely. The inspection included a review of Technical Specification 3.10 and licensee procedures, plus verification that applicable prerequisites, surveillance and precautions were satisfied. The inspectors also verified that appropriate radiolo-gical control measures were implemente A sampling of licensee procedures for refueling and in-vessel work was reviewed for technical adequacy, including:
+ MP 701.1, " Reactor Vessel Head Removal and Replacement" + MP 701.2, " Reactor Vessel Head Stud Tensioning" + MP 790.4, " Control of Heavy Loads" + OP 3288, " Fuel Loading /Unioading/ Shuffling" + OP 328C, " Fuel Transfer Using the Refueling Bridge" + OP 3280, "Contral Rod Removal and Replacement from Reactor Core" + OP 328E, "LPRM Removal and Replacement" +
OP 328G, " Upper Level Drywell Access Control Durir.g Spent Fuel and Irradiated Component Transfer"
+ RE 1071, " Spent Fuel Pool Verification" + SP 690C, " Functional /Subcritical Control Rod Checks" + REF 21001-1, " Materials Transfer Form" The inspectors witnessed the following activities to verify actions were completed in accordance with applicable procedure +
The inspector observed reactor pressure vessel (RPV) head detension-ing on April 10, and RPV head removal on April 13. The inspector noted that maintenance personnel used the proper safe load path and identified no procedural nonadherences for either evolution. The inspector did note, however, that Revision 3 of MP 790.4 was posted at the refueling floor in accordance with MP 790.4 Step 5.7.2.2 when Revision 4 was issued effective May 27, 1987. The inspector reviewed the additions under Revision 4 and concluded that they provided addi-tional information and did not impose additional requirements. The inspector discussed this matter with the Maintenance Supervisor, who stated that the refueling floor procedure copy would be updated. The adequacy of the controls for assuring current procedures are provided is unresolved and will receive further review (UNR 89-08-07). j
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Core offload was observed on April 15. The inspector verified that OPS Form 328B-1, the refueling checklist, was completed and conducted independent verification of significant items. The inspector noted that several senior reactor operators and a reactor engineer were present, the cattle chute was in place, and access to the 54' drywell elevation was secured. In addition, constant communications were . I _ __ '
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. -14 maintained with the control room and all refuel-bridge equipment was !
secured to avoid its falling into the reactor' cavity or. spent fuel 'j poo i'
+ The inspect'or observed control rod blade changeout on- April 27. -The core was completely off_ loaded to the spent fuel' pool at the tim The licensee identified a blade loading error at about 3:00 pm that'
day, in that the rod blade from spent fuel. pool location 3B was in-stalled in core location 34-11 instead of the intended location, 34-15. Licensee review determine'd that the error occurred when the blade transfer. sequence was not followed for steps 24.and 25. . Blade ; changeout continued with a corrected sequence after review o.f the {' matter with Reactor Engineering personnel. The inspector reviewed-licensee actions and identified no inadequacies. This failure t follow procedures was deemed.to be an isolated mistake, identified and corrected by routine licensee review. Since the correction took-place before completion of the activity, there was'no safety signi-ficanc i
+ Local power range monitor (LPRM) removal was cbserved on April' 2 )
As the core was offloaded into the. spent fuel' pool, the inspector noted licensee compliance with'an OP 328E requirement for the removal of the fuel assemblies adjacent to the LPRM. The operators conducted-the evolution carefully and safely, and Health Physics coverage was thoroug + The inspector observed core reload operations in progress on May'4-for movement of core components and fuel bundles LYS061, LYC504, LYS051, LYH051, LYC650, LYC616, LYC552, LYC579,- LYC545 and LYC499.- No inadequacies were identified. Licensee personnel demonstrated a good regard for nuclear and personnel safety during fuel handling and in-vessel > activitie i 7.0 Plant Modifications I l 7.1 Unit 1 Spent Fuel Pool Rerack Project The licensee implemented spent fuel pool oesign changes per PDCR 1- l 24-88 to increase Unit I spent fuel on' site storage capacity from 2184 .. assemblies to 3229 assemblies. The references used for the associ-ated NRC inspection are identified in Attachment A to this repor As part of the design change, the 15.ensee removed the supports and structural steel from the existing rack configuration, relocated th existing racks to a new location requalified for fuel storage in_ a i
" free-standing" mode,: and installed ten additional storage rack j 4 The new high density racks provide 1045 additional storage locati_ons, arranged in ten free-standing and self supporting modules in six dis-tinct sizes, with individual storage cells having inside dimensions i
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of 6.06 square inches. The new eacks are constructed from ASTM 240,. Type 304 stainless steel for structural members and Boraflex for-neutron absorption'. Boraflex is a silicone based polymer containing ' fine particles of boron carbide in a homogeneous matrix, and has bee found acceptable for the application by vendor testing for a minimum of five years of service. The licensee plans an in-service Boraflex performance monitoring program to assure continued acceptable service beyond five year NRR Review and Approval NRC:NRR review of the project was completed in phases concurrent with the licensee's construction schedule. Phase 1 involved review of the design changes associated with modifying and relocating the existing racks. NRC approval of this phase was provided in a safety evalu-ation dated August 22, 1988. phase 2 involved approval to install the new racks, which was provided by letter dated December 8, 198 Completion of phase 3 (review of thermal-hydraulic, criticality,'and-seismic aspects) will provide full approval of the requested license amendment. The Millstone 1 technical specifications do not- have a limit on the number of fuel assemblies that can be stored in the pool. The plant design basis, as defined in Amendment 39 dated June 30, 1977, considered the effects of storing 2184 assemblie NRC:NRR review of the 1Icensee's June 24, 1988 proposed amendment request is complete and has found the design change acceptable. How-ever, NRC did not issue the environmental assessment and safety evalu-ation to support the proposed amendment by the start of the refueling outage on April 8, 1989. NRC:NRR approved temporary use (for about three weeks) of 324 of the new high density storage locations to al-low full core offload of 580 fuel bundles. After refueling, the num-ber of bundles stored in the pool will be less than 2184. The inspec-tor verified that temporary use of the racks during the outage met licensee commitments to NRC:NR i NRC:NRR approval was issued by letter dated April 6,-1989, and was ! contingent upon a change to licensee procedures to inspect the new ; racks in the event of a design basis earthquake. The inspector noted i that the licensee changed procedure ONP 514C on April 8 to require i that, in the event of an operating basis or greater earthquake, the ' spent fuel pool rack-to-rack spacing must be inspected with "go-no , go" gages to ensure design limits have been maintaine No inade- ! quacies were identifie Design Change Implementation The inspector verified, based on a review of the references, drawings i and design change records, that the licensee demonstrated the fol- i lowing for the spent fuel pool rack project: i
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the design basis K-eff is maintained below the maximum of 0.90-i
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specific. analyses results demonstrated that structural,. civil, . U seismic, mechanical, and thermal-hydraulic. limits are satisfied, [ including a safety factor of 2.22 for adjacent; module. impact with a minimum intermodule gap of one inch and a bounding seis-mic. displacement of 0.438 inches;
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the revised accident analyses demo'nstrate acceptable consequences for analyzed ' events; and l -- simple Boraflex sheets will'be used on each side of the fuel cell, held in place by stainless steal sheathing. The sheathing I will not restrain the Boraflex sheets and thus will not: inter- i fere with radiation induced shrinkage. This provision addresses
.the concerns raised in NRC Information Notice (IN) 87-43; "Neu - .,
tron Absorbing Materials in Spent Fuel Pool Racks."
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in addit M , the boron loading for criticality control,is at-least 0.027 gm/cm2 of boron-10;
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the impact of the radiation induced changes.in the Boraflex wer accounted for in the reactivity analysis for the racks;
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there are provisions for Boraflex surveillance specimens and an inservice surveillance program to monitor Boraflex performance over tim The inspector reviewed installation of the new' racks and relocation of the old racks to verify the design change was implemented per th H design change package and the installation procedures. cThis review l included: rack handling, installation and leveling procedures; visual inspection of the rack configuration in the spent fuel pool to verify
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i conformance of rack placement, orientation, and spacing with as-built i '. drawings and the approved design; rack leveling data for conformance with the specifications of step 6.3.6 of installation procedure GC-SC-67; licensee QA verification of as-built rack spacing, vendor QA . records for rack welding and installation of Boraflex sheets; and ' vendor and subcontractor QA records for Boraflex construction showing acceptable poison isotopic, physical and chemical properties, trace- , able to certified raw materials with an acceptable boron-10 loadin No inadequacies were identifie ] The inspector noted the licensee did not- perform neutron. absorption - measurements upon receipt of the racks onsite. The licensee ex-plained the alternate measures to assure adequate safety. These-in-cluded licensee approved ver; dor procedures and licensee QA review of fabrication and installation, including in process inspection. Th inspector found these measures to be acceptable, but noted further
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that-the licensee had not yet developed detailed-surveillance pro-cedures specifying the: inspection plans and acceptance criteria for monitoring Boraflex performance. -The. licensee-plans'to' develop'the, procedures after the present outage; .this plan is acceptable'since the racks'have been determined to be qualified for.at,least five~ years of: servic In summary, no inadequacies were: 1dentified. Licensee actions to devel.op and implement procedures for the Boraflex surveillance pro-gram in accordance'with commitments to NRR will be examined on a sub-- sequent 1.nspection'(UNR 89-08-04).
7.2 Emergency Core' Cooling- System (ECCS) Suction Strainer Replacement'. A licensee drywell insulation ' study' concluded that fibrous insulation-debris during post-accident conditions could cause head loss to the
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low pressure emergenev ' core cooling 1 system (ECCS) by flowing to the: torus.and clogging the suction strainers. (See NRC' irs- 50-245/88-05, 88-07, and 88-17.) .To' assure adequate suction head.. replacement-strainers with greater surface area were-installe .
The inspector reviewed ass'ociated' plant design change record (PDCR)' I 1-33-88, Revision 0, to determine if~the modifications are:being-im-plemented in accordance with the controls specified in ACP-QA-3.10, i Revision 2, " Preparation, Review and Disposition of Plant Design Change Records." The inspector found that the plant'. design.chaine was properly. developed, reviewed, verified, and controlled . adequately
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by the responsible organization ' ' The inspector reviewed the licensee's safety evaluation-(PA 86-071) and found it to be both thorough and in conformance with 10 CFR 50.59 and licensee implementing procedure ACP-QA-3.08, Revision 4, " Safety Evaluations." The specific safety evaluations. reviewed by=the in-spector were' conducted by Generation Civil Structures, Engineering Mechanics, and Reactor Plant Systems. Additionally,'the inspector reviewed the seismic qualification evaluation performed for the pip-ing system, torus and pipe supports due to the increased loading created by the larger strainer The evaluations concluded that the additional' loads imposed by the strainers would not adversely effect .j the seismic margins, that the piping and supports are. adequate for j the revised loads, and the resulting stresses meet those allowable 1
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by the Mark I progra ; ..'UREG 0661), " Safety Evaluation Report Mark .I Containment Long-Term Program." The inspector identified no inade-' j quacies in the licensee's evaluation R
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The inspector conducted a field walkdown of the modifications associ- l ated with the suction strainers to verify design change implementa- ' tion. ~AWO M1-89-02887 was utilized to install the new torus l
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strainers and remove the old strainers. The_ installation require- 1 ments were controlled by NUSCo Specification d' -CE322, Revision 1,
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" Specification for Torus /ECCS Suction Strainer Installation." The inspector observed the handling and transportation of an old strainer and found adequate implementation of health physics practices. The strainer work was conducted under water by a diving contractor when the entire core was in the spent fuel poo The inspector noted that the only procedures affected by the design change would be the Emergency Operating Procedures (EOPs), which were revised to ensure adequate net positive suction head upon initial discovery of the problem. The licensee made no changes to the cur-rent Revision 3 E0Ps, which is conservative. The Revision 4 E0Ps will account for the new strainer area and are to be implemented by September 1989.
s The inspector also reviewed Design Change Notices DCNs 190-89 and 266-89, written against the strainer installation Specification SP-CE32 The DCNs were found to be in accordance with the ACP-QA-3.14,
" Design Change Notices for Design Documents." The inspector con-cluded that the observed modification work was properly implemented and supervise .3 Gas Turbine Generator (GTG) Governor Replacement The inspector reviewed adequacy and implementation of engineering, construction and quality assurance procedures involved in performing the GTG governor replacement and associated work. This project in-volves the following major element Replacement of the existing hoodward electro-hydraulic governor control system with a Woodward microprocessor-based system with a new hydraulic control and power uni Deletion of the existing relays and timers associated with the sequence logic since their functions are incorporated into the microprocesso Replacement of the existing fuel control hydraulics and fuel valv Addition of four and eight channel recorders for diagnostic Addition of a LOCA/ START bypass keylock switch in the main con-trol roo I --
Replacement and addition of inverter and 24VDC power supplie , i Also, protective logic modifications were made to bypass the follow-ing circuit breaker trips under accident conditions. A new control room annunciator was added to annunciate these bypasses:
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Loss of generator excitation;
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Opening exciter circuit breaker; i
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Negative sequence; and
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Reverse powe Licensee Program for Project Implementation The r , acement of the GTG governor system is being performed by the licensee under Plant Design Change Record (PDCR) 1-25-88 as Project Assignment (PA) 86-044. The inspector reviewed the PDCR and PA to- I determine the scope of the changes, reasons for the changes and.to determine how these changes are to be made from the initial. concept until the final construction completion acceptance. tests, and turn-over to operation The planning, scheduling, NRC notification, and implementation of GT governor system replacement has been conducted by the licensee under the Integrated Safety Assessment Program'(ISAP). Accordingly, the licensee has addressed the GTG governor replacement in the 1987 ISAP ; reports and in the latest ISAP report dated November 9, 1988. In the l November report, the description of the system was changed to incor- f porate NRC evaluations and NUREG-1184, " Integrated Safety Assessment Report (ISAR) for Millstone Unit 1," April 1987, comments on the GTG governor modification This plant modification is being conducted in accordance with 10 CFR 50.59, which permits making changes in the f acility as described in the FSAR without prior Commission approval ) unless the proposed change involves a change in the Technical Speci- i fications or an unreviewed safety questio The inspector reviewed the licensee's PDCR and PA descriptions of the ; GTG modifications for any conflicts with the licensee's ISAP descrip- i tions of the system to NRC and to NUREG 1184 Draft ISAR (Integrated ' Safety Assessment Report) evaluation of the system. No discrepancies were identifie ! Work Orders to Accomplish the Modification l i The modification work required to accomplish the GT governor system replacement is being performed for the most part by onsite Millstone craft personnel in accordance with station procedure ACP-QA.202C,
" Work Orders." Work orders are issued in accordance with this pro-cedure for specific work segments. The following completed work order packages were reviewed to determine compliance with these pro-ce6ures, i
MI-89-02771 - Install GT Governor Condui MI-89-02773 - Fabricate Relay Subpanel, Mount and Pre-wire Relays, i i I
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. 20 MI-89-03740 - Perform Wiring Changes in Control Room Panels 908, 3 '932 and 93 MI-89-03245 - Install New Relay Panel in Panel 3R, New Relays in Panel 2R, and Wire New Device i The work orders reviewed clearly defined the work to be performed-and i were found to be in compliance with station proceoures. These work j order packages included a description of any special material re- '
quirements including Class 1E, services, and service qualifications; QA/QC. inspection plan / requirements; and installation requirement , Materials, equipment qualifications, calibrations, and QA/QC inspec- ' tions were found to be in accordance with the work order procedural requirements, which were deemed to be adequat i Physical Inspections of the Modifications In order to assess compliance with the work orders and the quality-of the work, the inspector conducted.the following walkdown inspec-tions of completed and in progress modification Inspection of the modifications to control room panel 926, in-ciuding the installation of a new panel alarm annunciator, push j buttons and a demultiplexes uni Inspection of the modifications to control room panel 932 which ' includes the new class 1E GTG keylock LOCA START / BYPASS switch and associated rela i
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Inspection of the GTG control cubicle panels which included the ! new 90 GE HACA class IE relays and the associated Woodward 501 i microprocessor to HMA relay interface relay Inspection of the Woodward Hydraulic Power Unit including the GTG fuel control actuator, hydraulic pump assembly, reservoir, ) hydraulic lines and fuel connection I
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Inspection of the two new GTG control equipment racks, their wiring, and new equipment including the Woodward 50 micropro- ! cessor digital control system, the Topaz inverters, the recorder units, and the power. supplie From sampling examination of completed wiring, terminators and elec- ! trical equipment mounting within panels, the inspector concluded that the work was being performed in accordance with the work orders and i was of acceptable quality, Muct of the interior panel wiring was still in progress and wiring had not been laced or terminated. The 4 i mounting of the Woodward Hydraulic Control Unit appeared to be ratis-factor The licensee had taken action to initiate seismic retest of ; the GTG control panel rack with its mounted components, including the Woodward microprocessor electronic governor control equipment. This l l
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retest was found to'be necessary when. analysis of earlier test data revealed that two of the test accelerometers did not provide prepe outpu Retest will'be performed on a. spare: duplicate rack and-equipment while installation continue '
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Since many of' the GTG' instrumentation and control circuits interface-with Class IE-and non-1E circuits, a sample-inspection was made.t ' assess the' adequacy of. electrical separation ~in accordance with IEEE Standard:384-1981. Inspection was made of the separation between-Class IE control signal. circuits 'which also feed non IE control sig-- nal circuits'amd non-1E indication and alarm circuits. InLthese in- stances,.the licensee.has installed EI International: Series'FCA iso-lation amplifiers in the' analog signal circuit to provide the re-quired isolatio For these devices, the inspector reviewed the qualification. report which included type testing in accordance'with IEEE standard'323-1974 and seismic qualification by: analysis in ac-cordance with IEEE Standard 344-1975. ,No deficiencies were noted. . class 1E cable run was' required between control: room panel 932 an for the new LOCA START / BYPASS switch circuit. The inspector con - firmed the.use of Class IE cable, run with. existing class IE cable, as being acceptable. The installation of the new non-class IE Panel-Alarm . annunciator in control room' panel 926. required running a new class non-1E cable from the GTG' control cubicle ~ multiplexer to this' panel. The inspector confirmed the type of cable and its rout-ing in existing non-1E trays as being acceptable. No discrepancies were observed in licensee adherence:to IEEE standard class'1E separa-tion provision Since changes in design usually. occur during the course of design / construction / completion of a complex project such as~ this one, the inspector reviewed the procedures in use for accomplishing such changes. The licensee implements changes ~in' ongoing work by issuing a Design Change Notice (DCN)'in accordance with station procedure NEO 5.1 This procedure is specific in its requirements,'which include appropriate reasons for the change, approvals, and.indene'ndent re- ) i view, Changes which are categorized as 'significant (change in scope, function,- etc.) cannot be made without first obtaining an approved-revision of the PDCR'to cover the change. The'following. completed DCNs were reviewed for compliance with the. procedure. '
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DCN 214 89 - Add color code for customer provided cable to CW ;
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DCN 262 89 - Change power cable sizes to 3KVA inverter !
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DCN 252 89 - Multiplexer wiring change I No discrepancies were noted in these procedures. One of these DCN 'l authorized work to commence immediately with only the project engi- ; neer's signature (without independent review and upper management j approvals). Inspector follow-up revealed that the' project engineer is authorized by the DCN procedure to proceed with minor DCN changes
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..,- . 22 at his own risk in order to prevent undue work delays. Appropriate independent review and approvals are then required within four work-ing' days. Failure to approve the DCN as prepared by the project en-gineer could require. removal or rework. -The inspector reviewed several DCNs associated with the GTG modification and identified no instances of noncompliance with or abuse of the procedur The inspector observed much last minute engineering of the GTG gover-nor replacement modifications and that there seemed to be a high nun;-
ber of related DCNs. Initially, that raised questions about adequacy of preliminary engineering and configuration verification prior to shutdown and modification. .This observation was confirmed by the licensee, who stated that with the plant at power it was not feasible to open the control cubicles and panels either in the GTG building or in the control room to perform detailed wirirg, terminal, and space verifications because the work would require entry into a TS LCO. ' As a consequence, many of the work order drawings have required changes based upon findings made since shutdown as well as changes that have been necessitated to correct occasional errors found in the original installation drawings. The inspector questioned the licensee's-ability to maintain control of the accuracy and quality of.the modi-fication considering the short time interval scheduled for its com- "
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pletion with the substantial amount of work remaining.to complete the installation, check out, preoperational tests and turnover to opera-tions. The inspector n9ted, however, that acceptable quality had been observed during th? s inspection. 'At the exit meeting, licensee senior management stated that resources were made available for com-pletion of the project baseo ; mon preshutdown planning. However, unforeseen extra time needed for engineering, installation or testing could add to this time and the mosiification might not be completed on i schedule. The licensee stated thtt project accuracy and qualit I would not be compromised for the sake of the schedul I Upon completion of the GTG modifications, preoperational tests must ) be successfully completed prior to turnover to operations. The in- l spector reviewed the following test procedures which were ready for l PORC review / approval, but which had not been presented as ye T-89-1-34, Woodward 501 Digital Control System Set up and Powe !
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T-39-1-32, Ambient Air Temperature Senso T-89-1-37, Setup GTG Fuel Valve to Woodward 501 Microprocesso The procedures were clear, logical and were prepared to the proper i format. No attempt was made to evaluate these procedures for ex-plicit technical conten In summary, in spite of numerous project delays and drawing errors, the project was being conducted with due regard for safety and quality, i l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . . _ _ _ _ _ _
.: - .. - ... , .- , . 23 8.0. Maintenance The inspector o'oserved and: reviewed selected aspects of'the following safety-related maintenance, including procedural adherence, obtaining re-
_ quired administrative _ approvals and tagouts' prior to work initiation. pro-per quality assurance and personnel protection measures, and verification of proper system restoration and retest prior to its. return-to servic .1' Reactor Water Cleanup (RWCU) Valve 1-CU-2 Weld Repair - On April 20, the licensee determined that unacceptable crack indi-cations were present on pipe to valve weld CUAJ-5, which is located on the eight. inch diameter, 304. stainless steel suction pipe to valve
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1-0U-2. The licensee attributed the crack, estimated to_be inches in length and 0.2" in depth, to intergranular. stress corrosion-cracking (IGSCC) and made an immediate, nonemergency report to the NRC via the emergency notification syste The inspector reviewed.the weld overlay design per Project Assignment-(PA) BB-014 and calculation 88-014-1086GP. -Licensee calculations showed a conservative' estimate of flaw growth rate would cause the crack _to go through wall after 15 months of operation.' The licensee designed the weld overlay to ' restore full structural' integrity to the
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pipe sections by requiring a minimum. thickness of.0.25. inches and a half length of 1.17 inches. The licensee chose' minimum' weld overlay dimensions of 0.3 and 1.5. inches for conservatis Inspector followup included review of weld activities in progres; per-AWO M1-89-04381, including staffing and control of the remote welding equipment set up on tPe 14'6" elevation of the reactor building,'re--
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view of welder setup and welding activities in progress 'at the valve inside the crywell, and inspector review of .the final weld configura- ; tion to verify conformance with the repair' plan, general quality and ; final finish for post weld examinations. No inadequacies.were iden- ' tifie .i The inspector also reviewed Project Assignment 88-014 documentation, ; including PDCR 1-89-059, and the weld overlay repair plan per AW0' l 1-89-059. Completed nondestructive examination results of the final i weld showing acceptable quality. The review confirmed-that ASME' code l and design requirements were' translated into the repair pla '1
The licensee submitted his. repair plans to NRC:NRR for revie NRR approval is required prior to plant startup from the refueling out- ,! age. This area will be inspected as a plant restart readiness item i on a subsequent routine inspection (UNR 89-08-05). l t i l l l
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8.2 Standby Liquid Control (SLC) Explosive Assembly Replacement The inspector observed maintenance personnel replacing the "B" stand-by liquid control system squib valve explosive assembly on April 13 per AWD M1-87-0510 The inspector noted that the licensee only stocks one squib order at any one time; the squibs are red tagged upon receipt until one is satisfactorily tested. They then receive a green tag, signifying their qualification and enabling their us The inspector verified that the squib used on April 13 had a green tag and was from the same batch (purchase order 695033) as the re-placed charge. The inspector also reviewed AWO M1-85-11516 which
; documents satisfactory test fire results for one of the squib valves from PC 695033, and a satisfactory certificate of conformance for the PO, dated October 4, 198 A representative from the licensee's Quality Services Department (QSD), who was~ conducting a random QSO surveillance of the activity, discovered that Step 5.1.6 of. Maintenance Procedure 7-5.1, "Conax Explosive Valve Trigger Assembly Replacement," had not been com-pleted. This step requires the mechanic to remove the inlet fitting cap which was displaced into the squib valve body whea the "B" SLC system was actuated prior to charge replacement. It is notable that the maintenance crew had already begun to reassemble the squib as-sembly before the QSD representative discovered the error. The main-
, tenance crew then disassembled the squib valve and removed the end , cap. The inspector noted that, had the end cap been allowed to re- f side in the squib valve well, the operability of the SLC system would j have been questionable since the well has space to accommodate only i one end cap. Upon initiation of the SLC system, the newly severed l end cap could block "B" SLC system flow' or could effectively remove the SLC system from service by moving downstream and blocking the common SLC discharge pat j In response to the event, the licensee revised MP 705.1 (Revision 7) to require independent verification of Figure 8.4 by the Job Super-visor or Maintenance Engineer. Figure 8.4 now requires documentation of the set tal numbers and expiration dates of both explosive assem-blies and requires independent verification of the removal of the inlet fitting cap displaced into the squib valve body. The inspector determined that this practice should prevent recurrence of similar errors. Failure to follow procedures is a violation of 10 CFR 50 and TS requirements; however, since the error was identified and immedi-ately corrected by the licensee, was not NRC-reportable, was not con-nected to any previous violation, and occurred and was corrected be-fore the SLC system was required to be operable, no violation cita-tion will be issued in this instance. The inspector had no further questions (NCV 89-08-06).
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25 - 9,0 Surveillance
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, The inspector observed and reviewed selected aspects of the following.sur - veillances for conduct in accordance with current approved procedures, for-test result compliance with administrative requirements and technical specifications, and for deficiency correction in'accordance with~admini-strative requirements. No. inadequacies were. identifie SP 4020, " Intermediate Range Monitor Functiona) Test'.' on May SP 609C, " Functional /Subcritical Control Rod Checks" on May Individual Rod Timing Tests per SP 3288-3, " Fuel Cell Loading Data Sheet" on May .0 Licensee Event Reports The following Licensee Event Reports.(LERs) were reviewed to assess LER accuracy, of. corrective; actions, compliance with reporting requirements - and to determine if'there were generic implications or if further .infor-mation was require , " Rejectable Flaw in Cleanup. System Weld CUAJ-5." This event concerned the discovery, during i.nservice inspection on April 20, of a flaw in the 8-inch diameter reactor water cleanup -(CU)' CUAJ-5 weld (pipe to valve 1-CU-2 weld) faside the drywell. The flaw in the stainless steel piping was caused sy. inter.grann'ular stres corrosion and was rejectable per ASME Section XI criteria. . The. flaw was 3.5 inches long by. 0.2 inches deep in the nominal 0,5 inch thick pipe wall. The licensee designed and installed a full' strength weld ; overlay restore piping integrity per USAS B31.1 criteria. Further NRC inspection of this item is described in Section 8.0. The lic- .I ensee event report was reviewed and found to accurately describe'the event and the licensee's corrective actions. No inadequacies were identifie , " Reactor Scram on Turbine Stop Valve Closure," and 89-06-00, " Primary Containment Unidentified Leakage Rate.." Both events are covered in report detail 4.3. The inspector found the'LERs to be accurate and sufficiently detailed. No inadequacies were note .0 Plant Operations Review Committee 1 l The inspector attended several Plant Operations Review Committee-(PORC) -) meetings and verified that Technical Specification 6.5.1 requirements for .! committee quorum were me The meeting' agenda included reviews of plant El incident reports, plant design modifications, procedure revisions, and new J procedures. The inspector'noted that the committee discharged their func- ~ tions in accordance with TS 6.5.1 and that frank discussions and probing ! questions were. encouraged. No inadequacies were identifie .j
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12.0 Management Meetings Periodic meetings were held with station management te discuss inspection findings during the inspection period. A summary of findings was also discussed at the conclusion of the inspection. No proprietary information was covered in the inspection. The inspectors provided no written mate-rial to the licensee, i l
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ATTACHMENT A The following references were used in the review of the spent fuel pool design change per PDCR 1-24-88 to increase storage capacity to 3229 fuel assemblies, as discussed in Detail 7.1 of this repor PDCR in24-88, Spent Fuel Pool Rerack Project
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NU letter dated May 5,1988, Spent Fuel Pool Rack Modifications - Project Description and Safety Analysis Report
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NU letter dated June 24, 1988, Spent Fuel Pool Expansion Amendment Request
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NRC letter dated August 22, 1988, Spent Fuel Pool Capacity Expansion - ; Millstone Nuclear Power Station, Unit No. 1 '
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NRC letter dated December 8, 1988, Spent Fuel Pool Capacity Expansion - Millstone Nuclear Power Station Unit No. 1
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NRC letter dated February 3,1989,, Summary of January 13, 1989 Meeting ; Regarding Millstone 1 Spent Fuel Pool Capacity Expansion
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NRC letter dated June 16, 1988, Meeting on Millstone Unit No. 1 Spent t.cl Pool Rerack
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NRC letter dated April 6,1989, Spent Fuel Pool Expansion - Millstone Nuc-lear Power Station, Unit No. 1
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NU letter dated March 22, 1989, Response to Request for Additional Infor-mation Spent Fuel Pool Capacity Expansion
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NU letter dated March 1, 1989, Spent Fuel Pool Capacity Expansion - Addi- 1 tional Information
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NU letter dated February 14, 1989, Response to Request for Additional In-formation Spent Fuel Pool Capacity Expansion
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NRC letter dated February 3,1989, Summary of January 13, 1989 Meeting Regarding Millstone 1 Spent Fuel Pool Capacity Expansion 1
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NU letter dated December 2, 1988, Spent Fuel Pool Capacity Expansion - l Additional Information I
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NU letter dated July 29, 1988, Response to Request for Additional Infor-mation Spent Fuel Pool Capacity Expansion
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NU letter dated August 12, 1988, Response to Request for Additional In-formation - Spent Fuel Pool Capacity Expansion ;
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NU letter dated July 29, 1988, Response to Request for Additional Infor-mation Spent Fuel Pool Capacity Expansion :
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Boraflex Installation Records for Racks B and C-3
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BISCO QC Calculation Sheets for Boraflex Minimum Loading and Specific Gravity Determinations
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Specification SP-ME-645, Bid Specification for Spent Fuel Racks Millstone 1, Revision 1, 6/5/87
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Holtec Drawing 187, Revision 3, Test Coupon Assembly and Detail
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Automated Work Orders 88-07959 (Rack D-1), 07956 (C-1), 07955 (C-3), 07962 (E), 07959 (B), 07313 (F), 07957 (C-2), 07960 (D-2), 07961 (D-3) and 07311 (A) for rack leveling
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Installation Procedures GC-SC-67 and GC-SC-69
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Holtec Drawing 181, As-Built Rack Installation Holtec and Brand Industrial Services Co QA records for boraflex raw mate-
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rials; certificate of compliances to purchase order specifications; and analytical test results for chemical, isotopic and physical propertie _ , _ _ _ _ _ _ _ - _ - _ _ - - - - - - - - - - }}