IR 05000271/1986010

Insp Rept 50-271/86-10 on 860506-0630.No Violation Noted by Nrc.Major Areas Inspected:Plant Shutdown Operations, Restoration Activities & Phyiscal Security.Violation Noted by Util Re Core Loading Procedure

ML20204F246
Person / Time
Site:	Vermont Yankee
Issue date:	07/28/1986
From:	Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20204F236	List: IR 05000271/1986010 ML20204F230
References
50-271-86-10, IEB-86-001, IEB-86-1, NUDOCS 8608040133
Download: ML20204F246 (44)

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o U.S. NUCLEAR REGULATORY COMISSION

REGION I

Report N Docket N License No. DPR-28 Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169, Ferry Road Brattleboro, Vermont 05301 Facility Name: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Dates: May 6 - June 30, 1986 Inspectors: William J. Raymond, Senior Resident Inspector, Vermont Yankee Thomas B. Silko, Resident Inspector (Trainee), Vermont Yankee Cornelius F. Holden, Senior Resident Inspector, Maine Yankee Thomas Foley, Senior Resident Inspector, Calvert Cliffs Jin W. Chung, Lead Reactor Engineer, Plant Systems Section Richard K. Str eyer, Radiation Specialist, Effluents Radiation Protec ection Approved by: /. m 7/28/'fd

' T. C. Els g , Chief, Reactor Projects Section 3C Date Inspection on May 6 - June 30, 1986 (Report No. 50-271/86-10)

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Inspection Summary:

Areas Inspected: Routine, unannounced inspection on day time and backshifts by resident and region-based inspectors of: actions on previous inspection findings; plant shutdown operations, restoration activities, preparations to restart, and reactor startup; plant physical security; core reloading; committee activities; operator training; followup on potential generic items and concerns; the control rod scram anomaly on June 14, 1986; and the plant readiness for restart. The in-spection involved 567 hour0.00656 days <br />0.158 hours <br />9.375e-4 weeks <br />2.157435e-4 months <br /> Results: No violations were identified by the inspector However, one violation was identified by the licensee (failure to complete core loading per the procedure OP 1410 fuel load schedule - Paragraph 7.1.1). Also, further licensee and NRC attention is warranted to address issues raised as a result of the scram anomaly on June 14, 1986 (Paragraph 6.0).

8608040133 860729 PDR ADOCK 05000271 G PDR l

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DETAILS Persons Contacted Interviews and discussions were conducted with members of the licensee staff and management during the inspection period to obtain information pertinent to the areas inspected. Inspection findings were discussed periodically with the management and supervisory personnel listed belo Vermont Yankee Mr. J. DeVincentis, Engineer Mr. P. Donnelly, Maintenance Superintendent Mr. J. Pelletier, Plant Manager Mr. D. Reid, Outage Manager Mr. R. Wanczyk, Technical Services Superintendent Yankee Atomic Electric Company Mr. J. Hoffman, Engineer Mr. R. Oliver, Engineer Meetings and telephone conversations were held with the Vermont State Nuclear Engineer on many occasions during the inspection period. The inspector also attended a meeting of the Vermont State Nuclear Advisory Panel in Brattleboro on June 17, 1986. The meetings at the site were held to discuss the status of the plant and NRC inspections of the plant readiness to restart. Specific items of mutual interest were also discussed, including actions to assure standby liquid control system operability; replacement of NAMC0 contact blocks in plant safety circuits; repairs to the condensate storage tank; repairs to the core spray nozzle safe ends, and the resolution of a concern expressed to State officials by a local citizen regarding a potential problem with the new recirculation piping. The latter item was reviewed during a restart readiness team inspection, as discussed in Inspection Report 86-13, and none of these concerns were substantiate . Summary of Facility Activities The plant completed the extended recirculation pipe replacement and maintenance outage during the inspection period. Significant milestones achieved included the completion of induction heating stress improvement of recirculation system welds; restoration of the reactor vessel to normal service conditions; com-pletion of core reloading and baseline core physics measurements; preparation of the reactor and plant systems for operation; completion of extensive pre-startup testing; completion of a reactor vessel hydrostatic test and a primary containment integrated leak rate test; and, plant restart. Significant prob-lem items resolved during the period included the completion of interim re-pairs on the condensate storage tank; the completion of weld overlay repairs on the core spray nozzles; and, the identification and correction of parts problems in the solenoid valves on the control rod hydraulic control unit s e

The reactor was taken critical following a 9 month outage at 9:40 p.m. on June 30, 1986. A reactor scram occurred at 10:05 p.m. on June 30, 1986 due to faulty intermediate range monitors. NRC followup and review of the scram is documented in IR 86-1 . Status of Previous Inspection Findings The status of licensee actions on previous inspection findings was reviewed during this inspection to verify licensee management controls were sufficient to assure open NRC items were successfully tracked to resolution, and to verify that plant component / equipment issues were satisfactorily addressed prior to plant restart. The status of licensee actions on some of the more significant issues is summarized below and actions on other issues are dis-cussed in Attachment .1 (Closed) Follow Item 85-30-07: Evaluation of Bundle LY005. The licen-see's evaha'fon of the fuel bundle LY005 was documented in a memorandum by the reactor engineering supervisor dated May 9,1986. No damage was identified on the bundle during an underwater inspection using video equipment. Further, the forces applied to the bundle to get it " unstuck" from spent fuel position U48 were within the design limits of the bundl There was no damage identified in SFP location U48. The bundle was found acceptable for reuse. This item is close .2 (Closed) Unresolved Item 85-40-05: Recirculation Whip Restraints. This i item was also reviewed in IR 86-12 which addressed the licensee's calcu-lations to repair the welds on the recirculation whip restraints. The NRC staff reviews in that inspection found that the licensee's calcula-tions and weld repair plans were acceptable. The inspector reviewed the reinstallation of all whip restraints that would remain operabl The repairs made to restraints R6A, R7A, R68 and R78 were reviewed in par-ticular and found to be acceptable and complete per the design drawing No inadequacies were identified. NRC reviews of other structural steel welding by the same contractor indicate the weld discrepancy problem was an isolated case limited to the recirculation whip restraints. This item is close .3 (Closed) Unresolved Item 86-08-03: Core Spray Nozzle Cracks. The licen-see completed actions to perform a weld overlay repair of the core spray nozzle safe-ends using a butter temper repair methodology specified by the ASME code (case N432). NRC:NRR approved the repair technique in a safety evaluation dated June 16, 1986 and concluded that repairs were acceptable on an interim basis of one fuel cycle. The repair procedures and work in progress were also reviewed by the NRC staff, as documented in IR 86-13. This item is close .4 (Closed) Unresolved Item 86-01-02: Defects in NAMCO Contact Blocks. The

licensee completed actions to assure only acceptable contact blocks are

, installed in plant safety circuits. The hardware issue was resolved

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prior to declaring the associated system operable for plant operation b

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Programmatic issues remain open and are being tracked as separate in-spection items. NRC review of this item is discussed further in Attach-ment I. This item is close .5 (Closed) Violation 86-05-01: Inoperable SLC Syste Actions were com-pleted to revise standby liquid control (SLC) system functional test procedures and to verify that the SLC squib valves were operable for Cycle XII operation. The hardware issue was resolved prior to declaring the SLC system operable for plant operations. NRC review of this item is discussed further in Attachment I. This item is close .6 (Closed) Unresolved Item 85-40-06: Embedded Baseplates. This item was reviewed in inspections 86-12 and 86-13. The licensee submitted LER 85-15 Revision 1 dated May 2, 1986, which adequately described the resolution to the discrepancy. The licensee completed modifications and evaluations which adequately demonstrated the acceptability of three categories of embedded bas / plates installed at the plan The construction defect identified in LER 85-15 appears to be an isolated case. However, this conclusion could not be substantiated on the basis of the results of the nondestructive examinations performed on a sample of embedded plates. By letter dated June 13, 1986, the NRC staff approved the licensee's use of the Pressure Vessel Research Committee (PVRC) recom-mended damping values (ASME Code Case N-411) to the piping system analy-sis at Vermont Yankee. The PVRC damping values were used to reanalyze the loads for supports using embedded baseplates, which allowed a re-duction in the number of required support A variety of modifications were completed per EDCR 84-402, ECN #13 on seismic supports that use embedded baseplates of the type that faile The modifications reduced or eliminated the reliance on the embedded plate to assure proper attachment of the supports to the wall. Modifi-cations required on wall-mounted (category 1) baseplates were completed prior to declaring the affected systems operable as required for fuel loading and plant startup. The licensee further instituted a program, described in a licensee memorandum to File 3.2 dated May 28, 1986, to control the future use of embedded baseplates presently not in us Plant drawings and the physical plates will be tagged and/or marked to indicate that use of the plate is prohibited without further engineering review. This item is close .0 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. This review included the following security measures: guard staffing; verification of physical barrier integrity in the protected and vital areas; verification that isolation zones were maintained; and implementation of access controls, including identification, authorization, badging, escorting, personnel and vehicle searche s u

The inspector also reviewed the compensatory measures taken for excavation work completed within the isolation zone along the Southwest protected area fenceline on June 15, 1986. No inadequacies were identified except as noted belo .1 Protected Area Control While entering the site at about 2:00 p.m. on June 15, 1986, the inspector noted that well drilling equipment was set up in the isolation zone of the Southwest corner of the protected area. The well drilling equipment was in the area since about 5:30 p.m. on June 13, 1986. The drilling equipment, a 6-foot high dirt pile, and 5-foot deep pit were within the zone. Following a review with security personnel of the established compentatory measures, the inspector estimated that about a 300-square-foot area within the zone was not covered by the established control The inspector's concerns were discussed with the security shift super-visor, and actions were immediately taken to correct the deficiency with additional security personnel. Further actions were taken by 5:30 to use additional security hardware to supplement the other compensatory measures. The inspector reviewed the coverage of the zone in effect at 5:30 p.m., and no further inadequacies were identifie The adequacy of compensatory measures implemented by the licensee as a result of obstructing the isolation zone is considered an unresolved item (UNR 86-10-01).

The inspector noted that the well drilling equipment and obstructions were removed on June 18, 1986, and the isolation zone was restored to its normal statu .2 Demonstrations The inspector reviewed measures taken by security personnel on June 14, 1986 in response to planned demonstrations at the plant main gate by local citizen groups. No civil disobedience or problems occurred. As-sembly permits were issued by the local town and arrangements were made with the licensee to assign an assembly area on site property. The in-spector reviewed the security contingency plans with the security super-visor. No inadequacies were identifie The inspector reviewed contingency plans taken by the security force on June 26, 27 and 28, 1986, in response to demonstrators who arrived at the site entrance and blocked site access through the gates for several hours. The demonstrators left the site area after several hours on each date without incident. Security contingency plans and measures were acceptable. No inadequacies were identifie .

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4.3 Loss of Security Equipment A lightning strike near the station at 7:20 p.m. on June 1, 1986 affected security equipment in the central alarm station. The inspector inter-viewed security personnel and reviewed the status of security equipment to assess the extent of the damage and the actions by security personne The compensatory measures taken were appropriate for the equipment that was lost. There was no loss of security function or control. Shift manning was adequate to provide the necessary compensatory measure The compensatory measures remained in effect until 9:45 a.m. on June 2, 1986 when maintenance actions were completed to replace a power supply and return security hardware to a normal status. No inadequacies were identifie .0 Review of Outage Activities Plant tours were conducted routinely during the inspection period to review activities in progress and verify compliance with regulatory and administra-tive requirements. Tours of plant areas included the reactor building and the drywel Radiological controls were reviewed to verify access control barriers, postings, and posted radiation levels were appropriate. Plant housekeeping conditions and the control of hot work were verified to be in accordance with the requirements of procedure AP 0042. Shift logs and records were reviewed to determine the status of plant conditions and changes in operational status. No inadequacies were identified. Tours of the drywell were conducted to monitor and verify the proper restoration of systems and equipment. The inspector also conducted a closeout tour of the drywell on June 26, 1986 to verify conditions were acceptable for restart. The inspector noted that licensee closecut activities were still in progress at the tim No inadequacies were identifie The inspector attended daily outage meetings to keep informed of the daily outage activities. Plant activities and events that received further review are discussed belo .1 Condensate Storage Tank Leakage The licensee identified during this inspection that the condensate stor-age tank (CST) was leaking from the tank floor into the enclosure area around the bottom of the tank. The tank leakage was identified while completing followup investigations per Maintenance Request 86-0517, which was initiated on March 15, 1986 when water was noted leaking into the enclosure at a rate of about 494 gallons / day (or 1.3 liters per minute).

The leakage was slightly radioactive with a tritium level of 3.0 E-3 uCi/ml. This leakage correlated with CST water, which had a comparable tritium level and a specific activity of 3.0 E-6 uC1/ml. All leakage was contained within the moat, collected by the tank sump and processed by the radwaste syste .

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The licensee drained the CST, cleaned the tank floor and inspected the bottom for defects. Two through-wall defects, about 3/16 inches in diameter, were identified within several inches of the tank wall. The size and location of the defects correlated with the leakage observed from outside the tank. Actions were taken to inspect the weld seams on the tank floor and to complete ultrasonic testing (UT) of the entire bottom of the tank to identify the extent of material wastage. Samples of floor plate around the through wall defects were removed for examina-tion and the conditions of the sand fill beneath the floor were examine The UT examinations showed that the corrosion occurred mostly around the periphery of the tank within 1 to 2 feet of the wall, with significant material loss in three areas each several feet long. The three areas had significant material wastage, where the floor thickness dimension measured less than 0.25 inche There was no corrosion evident on the sidewalls and no significant corrosion evident over the majority of the floor area. Corrective actions were completed to weld patches of alumi-num plate over the three areas of high material loss, and to restore the floor thickness to the 0.25-inch minimum wall dimension required by the original construction standard for the tank, ANSI B96.1. The licensee's UT results and repair actions were also reviewed in Inspection 86-1 The licensee completed an engineering evaluation of the tank condition and the corrosion failure mechanism, and concluded that the repairs pro-vided an acceptable interim solution. The galvanic corrosion occurred when the area between the concrete base mat and the tank floor became wet following an overflow of the tank in 1976. The tank areas wetted by the spill remained wet and corrosion continued over the years until the through-wall leaks developed early in 1986. When the through-wall defects occurred, CST water wetted the entire area beneath the tan Even though the water has been drained from the area beneath the floor, the sand fill is most likely still wet and, therefore, corrosion is ex-pected to continue. However, the licensee's evaluation concluded that since the expected corrosion rates are 10-40 mils / year, and other meas-ures were taken to reduce the moisture beneath the floor, the probability '

of additional leakage during the next year has been substantially reduce Additionally, the ability of the tank to resist seismic loads was never significantly impaired due to the method of attachment of the tank side walls to the concrete base mat, which significantly reduces the loads

, experienced by the tsak floo Since minimum floor thickness of 0.25 inches has been restored in the affected areas, tank leakage is not ex-pected for at least the next cycle of operation. The licensee's evalu-ation was reviewed by the NRC Region I staff and found to be satisfactor The condensate storage tank holds about 500,000 gallons of water and

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provides a supply of water to several plant systems, including the RCIC

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and HPCI systems. The minimum volume of water required in the tank is 75,000 gallons to meet the Technical Specification 3.5 operability re-l quirements for the HPCI syste CST level indication is available in l the control room and monitored at least three times per day by the con-trol room operators. A low CST level condition is annunciated in the

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control room. Auxiliary operators are required by procedure to tour the CST area three times a day to monitor the enclosure, moat and sump areas for leakage. The inspector noted that a drain line from the tank bottom area is now open and being used to monitor for any additional leakag Slow drainage of residual vater from the sand beneath the floor was measured at 1.6 liters /hr. The licensee implemented a new special leak-age monitoring procedure for the CST (OP 4196) that requires a weekly inspection of the tank for leakage and establishes criteria for further action and evaluation if additional leakage is identified. The inspector noted that plant personnel had implemented the procedure prior to plant startu Based on the above, the inspector concluded that the licensee's interim corrective actions were acceptable to repair the tank floor and to pro-vide assurance that the minimum water volume required in the tank will remain available for the next operating cycle. In the event the licensee subsequently determines that the 75,000 gallon inventory cannot be as-sured, the present Technical Specifications would require that the plant be shutdow This item is considered acceptably resolved for plant restart. However, this inspection item is open pending: (1) NRC review of the licensee's leakaga monitoring program for the CST during subsequent routine inspec-tions; and (2) implementation by the licensee of long-term action to correct the CST corrosion problem (UNR 86-10-02).

5.2 Reactor Cavity Overfill While refueling operations were in progress on May 21, 1986, an imbalance in the water makeup to and letdown from the reactor occurred which caused the reactor cavity to overfill. Water level in the spent fuel pool and the dryer-separator pit also increased until the water overflowed into the ventilation duct at the top of the dryer-separator pit. The level increase was noted by personnel on the refueling floor, but the control room operators were not successful in identifying the source of the water in time to prevent the overflow. When the overflow occurred, the shift supervisor directed that RHR discharge flow be diverted to the torus for a sufficient time (about two minutes) to reduce cavity level below the ventilation intake. The source of excess water inflow to the vessel from the CRD system was subsequently identified and terminated. The inspector reviewed the consequences and the licensee's followup action for the event.

, Reactor water with an activity of 1.04 E-4 uCi/mi overflowed into venti-lation ducts that take suction around the top of the pit. Based on a

review of the ventilation ducting slope and interconnections, the in-i spector determined that very little water flowed into the ventilation

, system, and the cavity water that did enter the system remained confined

to the ducting above the 318-ft elevation. The pit ventilation is con-nected via transfer fans to the main reactor building ventilation system, l

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which in turn discharges unfiltered to the plant stack. There was no increase in activity measured by plant process radiation instrumentation either in the reactor building ventilation system or at the plant stack after the spil In addition to entering the ventilation system, water leaked from the duct at a joint in the overhead of the 318-ft elevation and leaked onto the floor, the RBCCW surge tank and associated equipmen Operation of the RBCCW system was not affected. Water leakage onto the floor was collected by the floor drain system and resulted in minor local floor contamination to levels up to about 5000 disintegrations per 100 square-cm. The amount of water spilled onto the 318-ft elevation was mino The licensee took actions to confine and control the potential surface contamination from the leakage, and subsequently to clean up tha affected area No inadequacies were identifie .3 Limitorque Motor-0perated Valves The licensee informed the inspector on June 13, 1986 of actions in pro-gress to re-address motor-operated valves (MOVs) that were overhauled during the outage to assure a potentially adverse condition was elimin-ated on safety system valves. The inspector reviewed the licensee's ac-tions to investigate and resolve the proble Following the failure of the "B" recirculation pump suction valve (V2-438) on June 4, 1986, the licensee's investigation determined the root cause of the failure to be a " hydraulic lock" condition in the limitorque spring pack that prevented the torque switch from operating properl Actions were completed under MR 86-1114 to replace the motor. The lic-ensee noted that grease from the gear box entered the spring pack area, and after filling the spring pack chamber, the grease interfered with compression of the Belville spring washers. A new less viscous grease, Exxon EP-0, recommended by the valve manufacturer which was used during overhaul of 40 MOV's during the outage apparently increases the likeli-hood of grease buildup in the spring pack chambe A modification package available from the vendor (apparently since 1975)

which provides a simple fix for the condition, consists of installing vent tubing from the spring pack chamber back to the limitorque gear bo Actions were completed by the licensee to install the vent tubing on all 40 valves. All valves were functionally tested satisfactorily by strok-ing in both directions following installation of the tubing. The in-spector determined that the licensee's actions to identify the root cause for the potential failure mode and to correct the condition on affected valves were appropriat At the conclusion of the inspection, the inspector noted that licensee review of this item was still in progress to consider the advisability of additional modifications for MOVs, and to determine whether the item is reportable under 10 CFR Part 21. Additional modifications to the spring pack internals is under consideration for future implementation

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pending the completion of an engineering evaluation of the spring pack desig If implemented, the change would further enhance the grease venting to the gear box. The inspector determined, based on further in-formation from the limitorque vendor, that installation of the external tubing alone would be sufficient to preclude a hydraulic lock condition from developing in the spring pac ,

The inspector noted that only one valve failed as a result of the over-

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haul work done this outage, and that the overall failure rate of valve motor operators was low. Other actions taken by the licensee this outage will serve to enhance MOV reliability. Routine surveillance testing per the Technical Specifications will prove continued operability of safety system valve The inspector determined that licensee actions were sufficient to address a concern for safety system valves prior to plant restart. This item is open pending completion and subsequent review of the licensee's fol-lowup actions on this item, and pending further NRC review of the ade-quacy of the licensee's system to receive updated product information from vendors (UNR 86-10-03).

5.4 Inadvertent Scrams l Several inadvertent scram signals occurred, while the reactor was shut-down, while testing or other work was in progress. No control rod motion occurred since all rods were fully inserted at the time. A summary of each event is presented below, i 5. A scram signal occurred at 7:46 p.m. on May 21, 1986 on APRM Hi/H1 Flux as a direct result of work in progress by instrument and control (I&C) technicians on LPRM circuits. The scram was l rese The inspector reviewed the flux indication from the onscale (source range) neutron monitors, as well as the alarm typer printout. This review confirmed that the inadvertent scram signal was generated by the APRM circuits and that there i were no other anomalous conditions present. No inadequacies were identifie . Two problems with the reactor protection system (RPS) were ,

experienced on June 9, 1986 while all rods were inserte The

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! first occurred at about 1:30 p.m. during the performance of the integrated ECCS test when a full scram signal was generated, I

as expected, upon temporary loss (13 seconds) of the RPS motor-generator sets during the test. The B RPS bus was restored l from its normal supply, but the A RPS bus was not immediately I re-energized from the normal supply (MCC 8A) due to a failed contactor on the output of the MG set. The "A" side scram '

(and Group III isolation) was not reset until 2:02 p.m. when i the A RPS alternate supply was established from MCC 88.

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An inadvertent scram signal was generated at 7:12 p.m. on June 9, 1986 while maintenance personnel were working on the failed contactor in the A RPS normal power supply. A broken pole piece on the SA-K1A contactor (normal supply) fell onto the SA-K2A contactor (alternate supply) as the workers were remov-ing the electrical panel cover, which caused the A RPS side to de-energize momentarily. A full scram signal was generated, since the B side scram instrument volume (IV) was still full of water from the 1:30 p.m. scram. The IV had not been drained due to maintenance in progress on the volume that required the drain line to be tagged close The licensee examined the failed SA-K1A contactor and noted the pole piece became loose due to a failure in its attachment to the contactor moveable assembly (GE Type 205PO - Part 55750324). Subsequent licensee inspection of the remaining three RPS contactors (5A-K2A, 5A-K1B and 5A-K2B) identified no similar condition . A full scram signal was inadvertently generated while starting

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the 8 recirculation pump at 8:41 p.m. on June 10, 1986. The scram signal was generated by the loss of the B RPS bus, which was powered by its alternate supply at the time due to main-tenance on the normal supply, and due to a spur.ioJs hi-hi flux signal from APRM channel C, which tripped the A side of RP The 8 RPS alternate supply tripped spuriously upon start of the recirculation pump due to action by the power protection panel. Spurious tripping of the alternate source concurrent with the start of large motors is a recurrent problem involving reliability of the alternate RPS supply, but is not a safety concern, since the loss of RPS power results in a safe condi-tio A half scram condition was in effect on the B side of the RPS prior to the event, which was caused when the B RPS power sup-

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ply was swapped from the normal to the alternate source at 7:30 p.m. The operators could not reset the B side scram after RPS power was restored. I&C personnel were troubleshooting this

, problem when the scram occurred at 8:41 p.m. The B side scram was reset during shutdown when corrective actions by I&C per-i sonnel energized a relay in the shutdown scram reset interlock Subsequent licensee review of the event determined

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circuitr that changes made ,ner plant design change request (PDCR) 85-03

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during the outage caused the shutdown scram interlock circuitry

to be subject to a relay race that could result in the inabil-

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ity to reset a scram in the manual scram circuit under condi-tions of a loss of RPS power supply. This is why the B side scram could not be reset after RPS power was restored prior to the scram. The relay race occurred only upon energization

following a loss of the RPS power. A temporary procedure and

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a jumper and lifted lead request (J/LL 86-115) were implemented on June 11, 1986 to provide a means to reset a manual scra A safety evaluation was prepared for the temporary change as required by Procedure AP 0020 and 10 CFR 50.5 The licensee completed a subsequent change to the shutdown scram reset interlock circuitry prior to plant startu The change was processed as a design change notice (DCN) to PDCR 85-03 and added a 1-second time delay pickup for relay 5A-K18 which would eliminate the relay race with relay 5A-K17 and eliminate the reset problem following a loss of RPS powe The licensee obtained an independent review of the final cir-cuit configuration by YNSD and GE engineering prior to instal-lation. The final circuit configuration was functionally tested satisfactorily as part of the PDCR 85-03 installation and test procedure. The interim procedure and jumpers were removed on June 26, 198 The inspector reviewed the circuit changes with the PDCR 85-03 cognizant design engineer and identified no inadequacies re-garding the new circuit design and operation. The inspector had no further questions on this item at the time. However, implementation of the PDCR 85-03 design change will be reviewed

, further during a subsequent inspection to review the adequacy of the post-modification functional test methods (UNR 86-10-04).

5.5 Support Discrepancies The licensee made a 4-hour notification to the HQ:00 on May 30, 1986 per 50.72(b)(2)(1), due to two SLC seismic supports that were found not in-stalled per design requirements. The supports were modified as part of the seismic reanalysis program (SRP) during the present outage, a 1d were discovered to be not installed correctly during final as-built verifica-tion inspections conducted per EDCR 84-402. The SLC discrepancies were dispositioned " accept as is", and would not have impacted system oper-abilit Two other support issues were identified during the week of June 2,1986, while the final EDCR as-built verifications were in progress. The first involved the discovery of errors in the original QA as-built drawings provided by CYGNA Energy Services, Inc. Actions were taken immediately to review the status of supports on the plant systems, then required to be operable, to identify the scope and nature of any additional discre-pancies. The accuracy of the CYGNA drawings on the remainder of the plant systems covered by the SRP program were reviewed as part of the EDCR 84-402 close-out. The second discrepancy concerned the discovery that welds on three service water supports were installed per the con-struction drawings, but not the design drawings. This event occurred due to a drafting error when making the construction drawings. Both support issues and the identified discrepant conditions were documented

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in Nonconformance Reports 86-88, 86-89 and 86-93, which dispositioned the findings and identified the corrective actions taken to achieve an acceptable resolution. None of the identified deficiencies were consi-dered significant, and none would impact the operability of the associ-ated system. The licensee's corrective action plan for the item was reviewed and found acceptable during Inspection 86-13. No inadequacies were identifie .6 Control Rod Friction Testing The licensee completed control rod friction testing during the shutdow All rods except 26-07 and 18-31 tested satisfactorily. Rod 26-07 would not move out at first, but eventually was moved under normal drive pres-sure and subsequently tested acceptably. However, the licensee changed out the drive mechanism. Subsequent friction testing on the control rod was acceptabl Control rod 18-31 tested satisfactorily except for a slow withdraw time (10 seconds versus 5) for the first notch out. The rod responded well over the rest of its travel and inserted acceptably. An initial decision to change out its drive was not implemented due to problems disconnecting the rod using the normal means, which is from under the reactor vesse The alternate means to uncouple the drive from above would require un-loading the fuel cell. After further evaluation of the rod with GE, the licensee determined that no safety problem would result from operating with the existing driv The slow withdrawal time for the first notch is due to a problem with the drive down seals, which affect drive opera-tion only over the first notch of withdrawal. The drive down seals would assist the rod scram function in the present conditio The inspector noted that control rod 18-31 tested satisfactorily during the single rod scram testing completed during the vessel hydrostatic tes No inadequacies were identifie .7 Calibration of the Stack High Range Monitor The licensee completed modifications on the stack high range noble gas monitor during the outage to address, in part, concerns raised during NRC Inspection 84-11. The licensee experienced difficulties completing a successful calibration of the monitor per procedure OP 4511 following the modifications. After further review of the installation setup and work at the vendor's facilities, the licensee determined that the detec-tor system was functioning properly, but an additional signal was being generated by irradiation of the caH e between the detector and the pre-amplifie The licensee installed a new detector which eliminated the intervening cable by mounting the preamp directly on the detector. The inspector reviewed calibration data .for tests completed on June 29, 1986 and noted that a successful in situ source calibration had been completed for the

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lower range of the detector system only. The inspector requested that the upper range be source calibrated as well. The inspector witnessed an additional source calibration of the upper range of the detector sys-tem on June 30, 1986. No inadequacies were identifie .8 Instrument Loop Errors The licensee informed the inspector on June 25, 1986 that YNSD engineer-ing reviews, completed while closing out the EQ project, identified the need for channel adjustments (setpoint changes) on instruments associated with reactor pressure and drywell temperature because of uncertainties in instrument loop errors. The inspector met with YNSD engineers on June 27, 1986 to review the bases for the recommendations, the reason for the previously accepted but now unacceptable loop accuracy assumptions, the significance of the previous inaccuracies, and the scope of the review effort that identified the need for action on the two identified para-meters. The inspector noted that of all instrument channels reviewed by YNSD for EQ purposes, only the drywell temperature and reactor pres-sure parameters were found to require further adjustmen The reactor pressure setpoint changes affected the high reactor pressure scram, the high reactor pressure recirculation pump trip, and the low reactor pressure ECCS permissive. Setpoint change requests 86-16, 17, 18 and 19 were implemented on June 29, 1986 to increase the margin be-tween the trip setpoints and the Technical Specifications limiting safety system setting The inspector reviewed the completed setpoint changes and noted the settings were consistent with the engineering re-commendations made in a memorandum dated June 17, 198 The licensee stated that an additional setpoint change (86-15) was in progress to adjust the setpoint on recorder TR-149-1, which provides input to a con-trol room annunciator for high drywell temperatur The inspector had no further questions on this item prior to startup based on the completion of actions to make the reactor pressure safety settings more conservative. YNSD engineering stated that further infor-mation will be supplied for NRC review, which documents all safety para-meters reviewed in the engineering study, the newly calculated loop errors, and the basis for accepting the established setpoints. This item is unresolved pending completion of the licensee's actions and sub-sequent review by the NRC (UNR 86-10-05).

5.9 Inadvertent Fire Suppression System Actuation The Cardox system inadvertently discharged into the West Switchgear room at 5:40 p.m. on May 23, 1986. The inspector observed licensee actions in response to the event to assess the actuation, securs the faulty equipment and establish a compensatory fire watch in accordance with Technical Specification 3.13.D.2 during subsequent periods when the sys-tem was out of service for repairs. The system was returned to service following recalibration of the ionization detectors which caused the inadvertent actuation. No inadequacies were identifie . - _ . - _ - _ - _ _ - _ _ _ _ _ - . . - . . _- _ .- - __ _

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5.10 RHRSW Motor Cooling EQ Upgrade The licensee scheduled work during the outage to upgrade electrical parts in the residual heat removal service water (RHRSW) cooling circuits to meet environmental qualification requirements. There were four solenoid-operated valves that required refurbishment, one in each cooling water line to the RHRSW pump motor oil coolers. However, replacement kits received onsite were incompatible with the installed ASCO valves. The licensee initiated actions to obtain the appropriate replacement parts, and to revise the RHRSW system operating procedure to eliminate reliance on the soleniod valves for plant restart, in case the replacement parts could not be received in a timely manne The inspector met with plant management on June 30, 1986 and stated that, notwithstanding the possibility that technically acceptable temporary changes to the RHRSW system operating procedure might be made, the RHRSW valves would have to be made environmentally qualified prior to plant operation above a reactor operating temparature of 212 F in order to remain in compliance with the requirements of 10 CFR 50.49. The licensee completed actions on June 30, 1986 to install rebuild kits on the RHRSW valves prior to reactor startup. The inspector witnessed the work. No inadequacies were identifie .11 HFA Relay Refurbishment The inspector reviewed licensee actions completed during the outage to complete replacement of lexan coils on GE HFA relays with a new type not subject to a previously identified failure mechanis Relays that are normally energized were addressed during previous outages and licensee effort this year concentrated on relays that are normally de-energize Work on the relays was completed earlier in the outag ,

During system operations on May 6, 1986, plant operators noted that the interlock that would prevent simultaneous opening of the HPCI torus and CST suction valves was not working. Investigation of the event deter-mined that the condition was caused by the incorrect reinstallation of relay contacts when the relay was reworked as part of the overhaul effor The contact configuration was corrected and the interlock was function-ally tested satisfactorily. The licensee concluded that the post-main-tenance functional testing per procedure Op 4363 was scheduled to be done and would have identified the condition had it been performed prior to May 6, 198 Further licensee review of the HFA replacement work determined that even though QC inspected the job, contact configuration of the rebuilt relay

, was not selected at an inspection attribute. Based on this finding and

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the May 6 event, licensee QC completed a 100% reinspection of all HFA 1 relays rebuilt during the outage and verified that the contact configura-

tion was as stated in the data sheets used by I&C technicians. As a re-

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sult, the QC review identified other potential discrepancies, character-l

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ized as differences between the data sheets and the contact development shown on the drawings or differences between the contact development shown for the same contact on different drawings. Of 150 relays reworked during the outage, 20% had a discrepancy of the type mentioned abov The inspector met with I&C and QC personnel on May 16, 1986 to review each of the known discrepancies, and to review, in particular, all po-tential problems in circuits associated with systems required to be operable for core loading. No hardware discrepancies were identified based on a review of the field contact configuration, a review of design drawings, and the satisfactory completion of functional tests on systems required for refuelin The licensee completed a review of all discrepancies identified by QC inspection and, with minor exceptions, identified no problems with the installed hardware. In addition to the review of each specific discre-pancy, the licensee concluded that the satisfactory completion of func-tional and logic tests performed on all safety systems prior to plant restart provided assurance that the plant hardware was acceptable. As a part of this determination, the licensee completed a review of all logic test procedures to verify that the assumed relay operation and contact configuration was prope The exceptions noted by the licensee involved relay 6A-K15 for the feed-water pump high vessel level trip, and inputs to either the computer or the annunciator circuit. The contact configuration for the feedwater pump trip relay was found opposite that desired, but proper operation of the trip function occurred due to another error involving the reversal of two wires between the relay and the terminal strip. The wiring error and contact configuration was corrected. The errors in the computer or annunciator circuits did not create an operability problem due to the ability to set the computer and annunciator circuits to match either a

"normally open" or 'normally closed" contact input configuratio The licensee stated that actions will be taken to correct the deficien-i cies identified in the control wiring diagrams. The schedule for this

effort remains to be established. This item is unresolved pending NRC l review of the licensee's schedule to update the drawings, completion of

the drawing revisions, and subsequent review by the NRC (UNR 85-10-06).

i i 5.12 Steam Dryer Inspection l

! The licensee completed a visual inspection of the reactor steam dryer

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during the outage (reference IR 86-04, Sectioa 5.2), and identified no discrepanices except a broken weld on three of the four lifting rod collars. The lifting rods are free standing and there normally is no contact between the rods and the collars. The collars are located near the top of the lifting rod and serve to align the rod with the dryer lifting assembly when moving the dryer. The collars are normally at-tached to the dryer wall by two brackets. On each of the affected col-lars, a through-wall crack occurred at the junction between the collar i a i

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and one of the two brackets. The crack was in the weld material and was

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caused by cyclic stresses due to dryer vibrations, which have now been

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relieve The licensee completed an evaluation of the dryer in the as-found condi-tion with the assistance of GE engineering and concluded that the reactor could be safely operated with the dryer in the.as-found condition for the following operating cycle. The broken pieces would then be removed during the next scheduled outage. The engineering analysis included

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, considerations for the cause of the failure, the function of the collars,

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the probability for additional failures, vibration concerns, the prob-

. ability of generating loose parts, and the assurance of proper support

to the lifting lug The inspector reviewed the engineering evaluations and identified no inadequacies in the conclusions. The inspector noted, based on a review of the FSAR and the engineering analysis, that no credit was taken for

the collars for dryer hold down support. No inadequacies were identifie / Inspection Report 86-04, Section 5.2, reported that a 2-inch stainless

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steel angle iron had cracked welds. That information was incorrec .0 Control Rod Scram Anomaly The results of single rod scram testing on June 13-14, 1986 showed unacceptable scram times for six of the 89 control rods. The scram tests were conducted with the reactor shutdown, but at full operating pressure, for the vessel hydrostatic test. Control rod 06-23 failed to insert, and rods 10-23, 18-11, 2?-35, 26-23, and 38-23 experienced a delay of about 5 to 7 seconds before m)ving when the scram signal was inserted for each rod. The licensee's im-mediate investigation identified that the ASCO air-operated valve on the hydraulic control unit (HCU V117 and/or V118) was the source of the problem.

l The scram circuit up to the V117/118 valves was operating properly since the solenoids de-energized promptly upon demand, but there was a delay in venting

the air pressure at the individual HCUs. Thus, in an actual scram condition, l , during which the backup scram valves would also open to vent the entire scram

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/ , pilot air header, all slow rods would have inserted.

.- The inspector noted that prior to discovery of the rod scram anomaly, the RPS (* and control rod system had been assumed to be operable for core loading (dur-

, ing which time all rods remained inserted), shutdown margin testing, and for

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insequence critical testing. Roughly 22% of the control rods were withdrawn for insequence criticals, including rods 10-23 and 26-23, which are separated by four cells in the core. The in pector reviewed core parameters and the testing completed prior to June 14, 1986 and determined that no unsafe condi-

. tio.1s occurred. The inspector noted further that plant Technical Specifica-l tion 3.3.A.2 would allow reactor power operations with up to six control rods t

with excessive scram times if certain conditions are met. Based on the above, the inspector concluded that the safety significance of the event was minima Actions were taken to correct the cause of the excessive scram times for the six rod L

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The licensee rebuilt all 178 HCU solenoid valves during the outage in accord-ance with EQ program requirements. The HCU V117/118 valves are ASCO air-oper-ated valves, catalog number LVA-90-405. ASCO rebuild kits #204-137 (valves)

and #204-139 (pilot head assembly) were used for the refurbishment. Two-hundred rebuild kits were purchased through GE and used during the outag An additional 200 kits were obtained during the followup of the June 14, 1986 event. Materials in both groups of kits were found to have parts that were outside accepted tolerence limit The licensee identified three root causes for the observed rod problem (1) The exhaust diaphram on V118 for roc 38-23 was installed backwards. This problem was caused by VY personnel when rebutiding the valves. (2) The spring was detached from the soleniod core in V117 for rod 06-23. This problem oc-curred because the spring was not completely attached to the core assembly when installed. And (3) the core' assemblies had oversized dimensions in the V117/118 valves for the remaining four rods. The oversized core dimensions were the result of a parts mixup where core assemblies meant for larger valves were included in the rebuild kits. Further review and inspection identified out of tolerencc dimensions on the inside diameter of the solenoid base as-sembly. This condition did not cause any of the observed VY failure The licensee worked with GE and ASCO personnel to develop a plan to inspect all critical dimensions on the rebuild kit mate.ials and to deliver a replace-ment group of certified acceptable parts to the site for use in the scram syste Inspection and testing of the parts were completed at the ASCO manu-facturing facilities and witnessed by four VY and YNSD engineering and QA per-sonnel. The certified parts were installed and functionally retested in the HCu Final functional testing will be completed during the single rod scram tests, scheduled after startup with the reactor at 25% full power, in accord-ance with Technical Specification 4. The licensee extended his followup actions to include a review of other air-operated valves associated with the control rods and on other safety systems at the plant. Only the air-operated valves (V31A/8) for the instrument volume vent and drains use the same type of ASCO valves. The valves were rebuilt with the certified kits. Although the backup scram valves, V140A/8, are a different type of ASCO valve, they were reinspected to assure internal dimen-sfons were proper and were rebuil The inspector reviewed the licensee's investigation and followup corrective actions over the period of June 14-28, 1986. Licensee actions to inspect the failed parts, investigate the cause, replace the questionable parts on the HCUs and other scram system valves, and to complete post-maintenance func-tional testing of the rebuilt valves were reviewed by the inspector and NRC Region I management. Based on a review of the above process, the inspector concluded that the licensee's followup actions were adequate to identify and correct the root cause for the scram anomalies identified on June 14, 1986, and that the scram s/ stem was restored to fully operable status for plant startu O a

Three issues that remain to be addressed include: (1) the adequacy of ASCO and GE QA controls, and the potential impact on other users of the question-able rebuild kits - a RICSIL was issued by GE and an IE Notice is pending from the NRC to address the VY experience to the industry; (2) the adequacy of the VY post-maintenance testing performed after the initial rebuild and prior to the June 14, 1986 scram tests - specifically, whether the licensee program met commitments made in response to the NRC's Generic Letter 83-28; and, (3) whether future single rod scram tests could be performed prior to shutdown margin and insequence critical testing (i.e., defer physics testing until after the vessel head is installed). This item is unresolved pending further NRC review of the above items (UNR 86-10-07).

7.0 Plant Startup Preparations and Activities The inspector reviewed the licensee's activities to recover from the outage and prepare plant systems for operations. The inspector reviewed the comple-tion of prerequisites identified on milestone punchlists and startup check-list Several major tests were witnessed and results were reviewed to verify system operability was appropriately demonstrated. System valve lineups were reviewed to verify the adequacy of the licensee's administrative controls to assure proper system alignment. Attachment III provides the listing of system lineups, tests and licensee activities reviewed. The tests and evolutions inspected are listed belo + Core Reloading + Integrated ECCS Test

+ Shutdown Margin Testing + Containment Type A Test

+ Insequence Critical Testing + Reactor Hydrostatic Test

+ Scram Time Testing + Reactor Startup The inspection of the above events determined that the licensee had detLiled procedures and milestone punchlists to adequately control restoration and startup activities, and to verify that startup prerequisites were satisfac-torily accomplished. Procedures and administrative controls were adequately followed, with minor exceptions, as noted in section 7.1 below. Measurements completed during the shutdown margin and insequence critical tests confirmed core parameters met expected values. Anomalies in the control rod system were identified and corrected, as discussed in section 6.0 abov Specific items are discussed further belo .1 Core Reloading The inspector reviewed preparation for core reload and activities in progress during refueling to verify Technical Specifications requirements were met, and that refueling activities were conducted safely and per the established administrative controls. The inspector witnessed the refueling activities from the control room and at the refueling floor for insertion of bundles LY 4810, LY 7008, LY 4786, LY 4840, and LYC 16 No inadequacies were noted, except as described belo .- _

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7. Misloaded Fuel Bundles

.. The licensee halted fuel moves at 5:30 p.m. on on May 18, 1986

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when refueling personnel noted that during move #20 on the fuel load schedule, bundle LJZ074 (from SFP AA-47) was inserted into reactor location 27-24 instead of LY 7022 (from SFP Z-47).

The error was corrected and refueling resumed. Fuel moves were halted again 6:20 a.m. on May 19, 1986 when it was determined bundle LY 7649 (from SFP E-44) was inserted into core location 29-18 instead of LYC212 (from SFP D-44). The error was cor-rected and loading continued until the reactor engineering (RE)

supervisor halted the activity upon arrival for the day shift on May 19, 1986, pending further review of the events. The licensee completed a partial core load verification and veri-fled the loading in the SFP. The inspector independently verified the core loading based on a comparison of the fuel load schedule, the tag boards, the partially loaded reactor

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and the status of loaded cells in the SFP. The inspector identified no further discrepancie The licensee concluded that the bundle misloadings occurred due to personnel error by the auxiliary operator who operated the refueling mast on both occasions. The first error was compounded by the failure of either the senior reactor operator in charge of the refueling and/or the RE assistant, who are responsible for assuring the core is loaded per the schedule, and who did not detect the error by the auxiliary operato Corrective actions were taken by the licensee to review the event with personnel involved in refueling, to counsel person-1el involved in the error, and to change procedure OP 1490 to better define the methods to be used by RE/SRO personnel to assure proper loading. The inspector reviewed the licensee's corrective actions and considered them to be prompt and effec-

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tive in correcting the deficienc The failure to complete core loading per the procedure GP 1410 fuel load schedule on May 18 and 19, 1986 is contrary to the requirements of Technical Specification No violation will be cited since the item was identified by the licensee l and the criteria of 10 CFR 2, Appendix C have been met.

l 7. Damaged Refueling Mast During core reload activities at 8:36 a.m. on May 20, 1986, the refueling bridge mast caught on a refueling tool hanging from the North wall of the spent fuel pool as a bundle was lifted for insertion into the reactor. The tool wedged between two horizontal structural supports on the telescoping mast and broke a weld on the end of one horizontal support. Refueling activities were halted pending evaluation and repair of the damage.

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The mast on the refueling bridge provides for rotational and lateral motion of the grapple to position it over the bale handle of core components. The weight of the core components is supported by the hoist cable within the mast. The horizontal supports provide stiffening of the main structural members of the mast and are spaced about one foot apart over its lengt The damaged horizontal support was removed completely. Site enginearing and GE determined that the structural integrity of the mast was acceptable without the one horizontal brac Checks were completed to assure that no interference occurred between mast sections due to bowing of the vertical structural member Subsequent operation of the mast was found acceptable and refueling continued at 4:20 p.m. on May 20, 1986. Refuel-ing personnel were instructed to remove items hung from the side of the pool that subsequently may interfere with bridge operatio The inspector identified no inadequacies in the licensee's resolution of the ite . Refueling Surveillances The inspector witnessed or reviewed completed surveillance re-sults for tests required to be completed prior to fuel loa No discrepancies were noted for the surveillances listed in Attachment III, except as described belo The inspector noted by review of form VY0pF 4117.01 "SGTS Per-formance Check," that the required ten hours running time per t

train per month may not have been satisfied for testing of SGTS Train "A". This item was brought to the attention of the senior operations engineer for resolution.

l Following his review, the licensee determined that the require-l ment had been met, but that the data sheets were improperly completed during the test. The licensee corrected the data sheets and discussed the matter with the auxiliary operator responsible for the errors to ensure he understood the purpose of the timer reading Further inspector review of previous surveillance data sheets indicated that the incident was an isolated case. The inspector had no further question .2 Core Verification Following the completion of refueling activities, the inspector completed an independent review of the final core assembly to verify the core was loaded in accordance with the core design performance reports. The final load pattern provided in Revision 8 to procedure OP 1411 was found to agree with the Cycle XII loading pattern specified by the engineering i

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group in a YNSD memo dated July 24, 198 This review verified that bundle loading orientation, seating and cell assembly were prope No inadequacies were identifie .3 Integrated ECCS Test The inspector witnessed the conduct of surveillance procedure OP 4100,

"ECCS Integrated Automatic Initiation Test," which tests the proper re-sponse of the emergency core cooling systems to automatic start signals concurrent with simulated loss of offsite power. The performance of plant systems during the first test conducted on June 8,1986 was satis-factory, except for the improper response of the residual heat removal (RHR) pumps, which failed to run as required due to the improper posi-tioning of key-locked switches on two suction valve Following correction of the above problem and verification that the test prerequisites were met, the test was successfully conducted on June 9, 1986. The inspector reviewed the test results for the performance of the diesel generators, and residual heat removal and core spray pumps and noted no inadequacie During the performance of the ECCS test on June 9, 1986, a full scram signal was generated as expected upon tempor-ary loss (13 seconds) of the RPS motor generator sets. A subsequent problem occurred when resetting the scram, as discussed further in sec-tion 5.0 abov .4 Reactor Vessel Hydrostatic Ten The inspector reviewed the conduct of the reactor vessel Class 1 hydro-static test on June 12, 1986, and noted that the test was completed satisfactoril No pressure boundary leakage was identified. Minor packing leaks were identified and repaired by the licensee. The seals on the "A" reactor cleanup pump were damaged during the initial pressur-ization and were repaired prior to continuing the test. No inadequacies were identified, except as noted belo The inspector noted an overpressurization of the RHR "B" loop discharge

/ piping occurred on June 12, 1986 during test. The outboard RHR low pressure coolant injection (LPCI) valve (V278) was CLOSED for the test and all downstream valves were OPEN to allow all Class 1 piping to be exposed to hydrostatic test pressures. The RHR piping upstream of V278 was pressurized when V27B leaked by its seat, which caused relief valve V35B to open. Relief valve V35B opened at 450 psi and discharged through a 1-inch line to the outboard shell of the torus. The affected RHR pip-ing has a design pressure of 450 psi at a reactor operating temperature of 300 F. The spilled water was cleaned up. The inspector requested the licensee to evaluate the event to determine whether low pressure RHR system piping was adversely affected by the even .

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The licensee's review of the event and conclusions were summarized in a memorandum to the OP 4101.1 File dated June 22, 1986. Leakage through V278 was noted by plant operators just prior to reaching the 500 psi inspection plateau. Actions were taken within 30 minutes to isolate the seat leakag Relief valve V350 did not lift again when reactor pressure was increased to the full test pressure of 1097 psig. The licensee con-cluded that the low pressure RHR piping remained within the allowable pressure range and that no equipment damage occurred as a result of the event. No inadequacies were identifie .5 Containment Type A Leakage Test The inspector witnessed the conduct of the 10 CFR 50 Appendix J Type A test on the reactor containment system on June 20-23, 1986. The test was also reviewed during Inspection 86-14. Containment leakage in the

"as found" condition was found to exceed Technical Specification '

acceptance criteria on June 21, 198 The inspector reviewed plant ac-tions to identify and repair the leakage sources, which were principally caused by leakage from the shaft seals in the drywell to torus vacuum breakers, and from the personnel batch in the drywell head. Following completion of repairs, the containment system was retested again satis-factorily. NRC staff review and followup of the test failure and cor-rective actions will be described further in Inspection Report 86-1 No inadequacies were identifie .6 Reactor Startup The inspector reviewed the preparations in progress on June 28-30, 1986 to begin a reactor startup in accordance with Procedures OP 0100 and OD 0101. The completion of prerequisites in the startup punchlist and the precritical checklist were reviewed with shift personnel. The status of plant systems was reviewed and found properly aligned for restart, based on a review of control room indications and a walkdown of safety systems in the reactor and turbine buildings. No inadequacies were identifie The inspector witnessed the reactor startup to critical at 9:40 p.m. on June 30, 1986. The startup was conducted in a professional, controlled and orderly manner. No inadequacies were identifie The subsequent reactor scram due to failures in the intermediate range monitors was reviewed, as documented in Inspection Report 86-1 .0 Committee Meetings The inspector attended meetings of the onsite and offsite ccmmittees that review plant operations to verify the committees functioned in accordance with the requirements in Technical Specifications 6.2.A and 6.2.8. The inspector attended a meeting of the Nuclear Safety Audit and Review Committee (NSARC)

on May 6, 1986 (86-4-R) in York Harbor, Maine. The inspector also attended

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meetings of the Plant Operations Review Committee on June 3, 1986 (86-42) and June 26,1986 (Special-Plant Restart). The committee activities for May 6, 1986 and June 3, 1986 were accurately reflected in the meeting minutes. Both committees appeared to be effective in providing an oversight function for plant operations. No inadequacies were identifie .0 Followup of Potentially Generic Items and Concerns The items below were reviewed based on information received from NRC Region I or discussion with plant workers that indicated a potential problem may exis .1 Potential Failure Mode for the RHR Pumps - IEB 86-01 IE Bulletili 86-01 was issued to licensees of GE BWR facilities on May 23, 1986 to request those licensees to review the RHR system logic design to determine whether a design problem identified at another facility was applicable at their facility. The problem described in the bulletin concerned the potential failure of a single flow instrument that could cause all four RHR pumps to become inoperabl The inspector discussed this item with plant management on May 30, 1986, who indicated that the subject bulletin had been received and that a pre-liminary assessment determined that the concern was not applicable to V The inspector subsequently reviewed drawings G191172 and G191301, Sheets 1268, 1269, 1248 and 1249, with a licensee engineer. This review determined that there are two separate, independent flow switches and minimum flow valve logic / control circuits at VY, and therefore, a single active failure of any one flow switch could not render all RHR pumps inoperable. The inspector had no further questions on this item. The licensee's bulletin response will be reviewed during a subsequent routine inspectio .2 SLC Fuse Coordination The inspector received notification from NRC Region I on June 19, 1986 of an event at another facility during which the standby liquid control (SLC) system failed to operate when tested. The event occurred due to a lack of proper fuse coordination in the SLC control circuit, a problem that was previously addressed to the industry in IE Circular 77-09 and GE SIL 236. The inspector discussed this item with the licensee and noted that the SLC fuse coordination issue was previously addressed at VY during design changes completed per PDCR 77-0 No inadequacies were identifie .3 Potentially Discrepant Materials and Practices During discussions with receipt inspection personnel on June 5,1986, questions were raised whether crack indications on 1-inch nuts received under purchase order (PO) were 28160 appropriately dispositioned on May

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20, 1986. The inspector reviewed how the item was dispositioned with the maintenance engineer, as documented on material disposition request (MDR) 86-17 Suspected crack indications on the surface of the nuts were determined to be a surface condition consisting of slag deposits that resulted from heat treating of the material. The inspector examined the nuts and concurred with the licensee's determinations _ However, of five nuts sampled of the 50 nuts received, only one was selected for buffing and additional visual inspection. The inspector requested that the remaining four nuts be buffed to verify that the slag deposits are readily removed. This item will be reviewed during a subsequent inspec-tion, pending final licensee documentation of the MDR 86-173 examination results (UNR 86-10-08).

During discussions with receipt inspection personnel on June 5, 1986, questions were raised whether carbon steel fittings returned to stores on April 10, 1986 by the Recirculation Task Force under MR Slip 04B 213 were acceptable. The three items were initially received as part of P0s 1630 and 1631 in the early 1970s. Material from the P0s was found de-ficient, as documented in NCR 76-3, and the apparent oisposition of the-NCR was to return the defective material to the vendor, cancel the order and stop using the vendor. The inspector met with the administrative supervisor and requested the item be reviewed to determine whether the material received in stores in April, 1986 was defectiv Following a review of the material and search of the P0 and QA files, the licensee determined that not all material from P0s 1630 and 1631 were defective. After receiving about 90% of the original order in 1976, 50%

of the material was rejected and returned to the vendor, and 40% was kept since it was found acceptable. For each of the discrepant cordition details documented in NCR 76-3, the licensee was able to identify mate-rial shipment notices which sent the affected material back to the vendo The licensee concluded that any of the remaining material that was kept and used was acceptabl The inspector reviewed the licensee's documented evidence and concurred with the 'icensee's conclusions. However, the inspector requested the licensee r.o identify the material from the subject P0 that still may be available in stores and to conduct a sampling review of the items for evidence of material defects. This item is unresolved pending completion of the licensee's actions and subsequent review by the NRC (UNR 86-10-09).

During a telephone interview with a former licensee contractor employee on June 5, 1986, questions arose regarding the adequacy of licensee con-trols in the areas of processing maintenance requests, control and use of vendor manuals, and receipt inspections. The contractor did not identify any problems that would constitute known safety concerns, nor did he provide information of any specific material discrepancy that the inspector could follow up. However, the individual felt that his con-cerns and suggestions offered to the licensee while working at the site were not acted upon to his satisfactio .

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The inspector queried the contractor regarding his concerns with the con-trol of plant systems under the MR process, and based on his knowledge of the process, the inspector concluded that there were no concerns identified that would indicate a loss of control of equipment in plant safety systems. Additionally, following the June 5, 1986 conversation, the inspector reviewed the surveillance and problem identification re-ports on record at the site that were completed by the contractor during his employment with the licensee. No problems recorded by the individual appeared to have been inappropriately resolved. Based on the above, the inspector determined that there were no indications of a problem that would constitute an immediate safety concern. However, the areas for which the contractor identified general concerns will be reviewed during a planned NRC QA inspection. This item is unresolved pending completion of the NRC QA inspection (UNR 86-10-10).

10.0 Operator Training Issues 10.1 Emergency Operating Procedure (EOP) Training During the restart team inspection (June 2-6,1986) several potential problems were identified related to the readiness of operators to resume plant operations following the extended outage. These issues were training for implementation of emergency operating procedures (EOP) and trafr.ing on modifications completed during this outage, and are docu-mented further in Inspection Report (IR) 86-1 Several operators (about six) had expressed to the inspection team a need for additional E0P training, principally the past use of the Dresden versus Vermont simulators for training on ECPs. In addition, the NRC restart inspection team found that training conducted on modifications completed during the outage was inadequate. In order to further evaluate these concerns, interviews were conducted with plant management and supervisory personnel and operators, as discussed belo On June 19-20, 1986, Mr. E. C. Wenzinger of the NRC Region I Office met with principal members of the Vermont Yankee Operations Department and discussed emergency operating procedures. The meeting attendees incleded the operations superintendent, his two assistants, the senior operations engineer, all shift supervisors, except one, all supervisory control roem operators, several other licensed SR0's and several control room opera-tors and auxiliary control room operators. The principle conclusions reached during the interviews are given below, and further details cre given in Attachment I Senior operations department personnel, management and first line super-visors were satisfied with the quality and quantity of training received on E0Ps. No further training on the VY or any other simulator was con-sidered by them to be necessary prior to the next startup. Many suggested that E0P training in the future should be conducted along with (as part

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of) routine drills of routine evolutions, not drills principally on E0P' All interviewees believe that they are ready to implement the new E0Ps no Some believed more-junior crew members should have additional E0P train-ing as well as additional training on routine evolutions such as startup and scrams during future routine training sessions. All considered the training on the modifications acceptabl The NRC staff also reviewed VY management involvement in evaluating the operators and their supervisors' ability to implement the new E0Ps. GE training personnel provided, in the Fall of 1985, summary evaluations of all six crews' abilities to implement the E0Ps based on simulator training. The evaluations were very brie VY management agreed that although the GE evaluations showed that the operators were adequately trained on the E0Ps, they did not provide sufficient information for management to make an in-depth assessment of the operators' readiness to implement the new E0P Following the operator interviews and in consideration of the NRC staff findings, VY management committed to conduct walk-through training for each shift supervisor and supervisory contrcl room operator on the E0P The walk through would be conducted in accordance with a memorandum from the plant manager to the senior resident inspector dated June 24, 1986, as summarized below:

" Vermont Yankee will drill (walk through) each SS/SCR0 on the E0Ps using the Control Room or Simulator (w/ dead panels). The purpose of the drill will be to assess the ability of the SS/SCR0 to pro-perly implement the E0Ps. We will not drill each path of each E0 The Training Department will prepare and conduct the drills. The drills will be observed by the Operations Supervisor or the Plant Manager. A critique will be held after each SS/SCR0 drill. The l Training Department will evaluate the SS/SCR0 performance and docu-l ment the results. These evaluations will be approved by the ob-server (Operations Supervisor or Plant Manager)."

The resident inspectors reviewed the licensee's actions and determined the above commitment was met. The inspectors witnessed a sample of the walk through training completed for two crews on June 24, 1986. The five shift crews that would start up the plant would be evaluated prior to plant restart, and the remaining individuals would receive the evalu-ations prior to resuming shift duty following restar The evaluation scenarios included drills of five casualties (Scram, ATWS, Small Break LOCA, Stuck Open Relief Valve, and Feedwater Line Break),

l which involved additional failures of redundant safety systems to drive l the exercise to damage states beyond the design basis. The instructors i gave oral evaluations of the crews performance following each of the five l

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scenarios. The simulator was then used to repeat the casualty for some of the events. The plant manager and the operations supervisor partici-pated in the evaluation Based on the above, the licensee met his commitment to provide additional training on the new procedures, and certification of the ability of senior plant operators to perform their licensed duties under the new emergency operating procedures. This item is open pending subsequent NRC revicw of the final documentation of the evaluation process, and verification that the remaining senior licensed personnel receive the training / evaluations prior to resuming shift duty (UNR 86-10-11).

10.2 Upgraded Outage Modification Training Major modifications performed during the 1985/86 outage were incorporated into the Licensed Operator Requalification Training Program. Six shift crews including the shift supervisor, senior control room operator, con-trol room auxiliary operators and shift engineer were provided this training. Two shifts were provided the training several weeks before the last shift training which occurred on June 25, 198 The original two training periods did not include a limited amount of information about some modifications. This information was provided in a revised syllabus to the remaining crews. The inspector attended one session of training utilizing the June 2, 1985 revised handou The objectives of the training were to understand the general reason for the modifications, to describe the modifications. Most of the modification training pro-vided the reason for the change, description of the change, and any changes in the control room indications or control Because of the modifications added to the syllabus after the two original crews were trained and the additional explanation provided of the complex modifications, the licensee committed to provide on shift instruction

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to those original two crews who did not receive the full modification l training. Tne last shift received the upgraded training while on shift I

on June 30, 198 Based on the above, the licensee met the commitment to provide revised codification training to the operator .0 Radiological Environmental Monitoring Program l

The inspector reviewed the licensee's Radiological Environmental Monitoring Program annual report for 1985. As a result of this review, the inspector determined that the licensee has generally complied with the Technical Spect-fication requirements for sampling frequencies, types of measurements, analy-tical sensitivities, and reporting schedules. Exceptions to the sampling and analysis program were adequately explained, e.g., loss of sample due to van-dalism. The report included summaries of the laboratory quality assurance program and of the land use surve The analyses of environmental samples indicated that doses to humans from radionuclides of station origin were negligible.

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12.0 Management Meetings The inspector held meetings with licensee management periodically during the inspection to discuss the inspection findings. A summary of the inspection findings was discussed with the plant manager on July 3, 198 .

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, ATTACHMENT I The status of licensee actions on previous inspection findings was reviewed to verify licensee management controls were sufficient to assure open NRC items were successfully tracked to resolution, and to verify that plant component / equipment issues were satisfactorily addresse (Closed) Follow Item 84-10-01: Fuel Failure Mechanism. The licensee examina-tion of fuel bundle LJU720 during the outage following Cycle 10 operation identified a single failed fuel pin (B4). The initial pin failed as a result of " random pellet clad interaction failure". There was no evidence to suggest the failure occurred due to an overpower event. Additional reviews are planned of the fuel bundle operating service history. The failed fuel pin was removed from the bundle and the bundle was reconstituted and returned to service in the reactor for Cycle 11 operation. No subsequent fuel failures occurred in Cycle 11. The basis for the licensee's actions were documented in a memorandum from the reacter engineering supervisor dated July 20, 198 This item is close (Closed) Follow Item 84-12-05: Conduct of Special Stability Testing. No special testing was subsequently performed. The inspector noted based on a review cf Amendment 92 that the provisions for special stability testing were subsequently removed from the technical specifications. This item is close (Closed) Follow Item 84-21-06: PIR for Core Power / Flow Anomaly. The inspec-tor reviewed the plant information report for the event and noted that the licensee's conclusions and corrective actions were as described in the in-spection reports and licensee event report associated with the inciden Corrective actions were previously inspected by the NRC, This item is close (Closed) Violation 84-08-06: Inoperable HPCI Syste This item was last reviewed in IR 84-21 and was open pending a review of licensee actions to resolve a potential human factors deficiency involving the HPCI system. In letter FVY 86-30 dated March 31, 1986, the licensee sunmarized the results of the detailed control room design review (DCRDR) and the proposed resolution to identified human engineering discrepancies (HEDs). One of several items that will be corrected by design changes planned for implementation during the 1987 outage is the addition of indication for the condition in which HPCI l initiation is blocked. This action satisfies the identified concern. Final l NRC review and acceptance of the licensee's actions for the DCRDR effort (TAP Item I.D.1 and NUREG 0737, Supplement 1) will be the subject of an evaluation

by NRR at a later time. This item is closed.

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' (Closed) Unresolved Item 83-17-08: Supports on Torus Piping. The inspector interviewed licensee personnel and reviewed the completed design changes done per EDCR 83-23. Licensee work activities under this EDCR were reviewed on a previous inspection while work activities were in progress. The inspector noted that the pipe supports were upgraded on the torus attached piping in September, 1983, in accordance with the commitments established in the NRR letter dated June 17, 1983. No inadequacies were identified. This item is closed.

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Attachment I 2 (0 pen) Follow Item 83-17-09: Service Water Pipe Supports. The inspector in-terviewed licensee personnel and reviewed the completed design changes done per EDCR 83-21 to correct pipe support inadequacies caused by errors in the hanger spacing table. The completion of work under this EDCR was reviewed during a previous inspection while the modifications were in progress. The completion of licensee actions to meet the commitments in Confirmatory Action Letter (CAL) 83-04 was documented in NRC Region I IR 83-17. The inspector noted that the EDCR 83-21 design changes were completed in September 1983 in accordance with the CAL 83-04 requirement This item remains open pending further NRC review of the licensee's corrective actions (as listed on page 27 of IR 83-17) to prevent recurrenc (Closed) Unresolved Item 85-23-05: Battery Size. The licensee installed new C&D LC-31 station batteries during the outage as a one-for-one replacement for the old batteries. The adequacy of the battery size was demonstrated acceptable by YNSD in Calculation VYC-298, as transmitted to the site by memo OPVY 809/85 dated October 16, 1986. The calculation showed that the new bat-teries are adequately sized to supply DC loads by the 8-hour duty cycle de-scribed in the FSAR. The calculation allows margin for future load growth and temperature correction. The inspector reviewed the calculations and identified no inadequacies. The calculations also showed that operation of batteries with one cell out of service as permitted by the technical specifi-cations is acceptable. The inspector's initial concerns are considered ade-quately resolved for operation of the station 125 Vdc syste The inspector noted that YNSD reconmended that plant proc'dures e be changed /

clarified based on assumptions used in the calculatior This included the need to clarify instructions to the reactor operater to transfer the supply for the vital MG set and emergency lighting leads after 30 minutes into the duty cycl The procedure changes will be reviewed on a subsequent routine

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l (Closed) Follow Iten 85-20-03: Battery B Ground. Subsequent licensee main-tenance actions eliminated the ground on the "B" station battery due to a fault in the control circuitry for the "B" recirculation motor generator se The B MG set was subsequently 'run satisfactory following replacement of the recirculation piping, with no adverse affect on the battery. This item is

! close (Closed) Follow Item 84-08-03: Station Batteries. The licensee completed ac-tions during the outage to replace both 125 Vdc station batteries. This ac-tion eliminated any concerns regarding the potential degradation of the cell The replacement batteries are less susceptible to the mossing problem observed on the old cells. The replacement of the station batteries was reviewed on

, a previous NRC inspection. This item is closed.

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Attachment I 3 (Closed) Unresolved Item 86-01-07: Appendix R Fire Watches. The inspector reviewed licensee actions to meet fire protection requirements per Appendix R. The licensee stated that design changes had been completed during the outage as required by previous commitments to address hardware items needed to satisfy Appendix R requirements. However, since several exemption requests still required NRC staff approval, compensatory measures were still required for several plant area Fire watches were re-established for the designated areas on May 17, 1986 concurrent with the reloading of fuel in the reactor vessel, which was consistent with the reinstatement of plant system operabil-ity requirement The inspector reviewed the discrepancies and the plant locations covered by fire watches and noted that the compensatory measures were consistent with the actions previously reviewed and accepted. The inspector also reviewed the implementation of the fire watches (patrol of the designated areas once every two hours) and identified no inadequacies. The inspector noted that auxiliary operators and shift engineers completed the fire watch patrols, which would occupy a single individual for one-half hour per patrol, four times per shift, for a total of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> on any one shift. The inspector noted that a shift engineer would remain in the plant buildings and be able to re-spond to the control room within 10 minute No inadequacies were identifie NRC staff review of the actions required to meet Appendix R program require-ments is tracked through inspection item 83-26-01 and will be reviewed further on a subsequent inspectio The licensee informed the inspector during this inspection that a letter had not been submitted to NRC Region I regarding the temporary suspension (January-May, 1986) of the fire watches, as previously agreed, because of an admini-strative oversight. The licensee stated that such a letter could still be sent to Region I, but the inspector ccncluded that such information submitted after-the-fact would serve little purpose. The licensee's failure to meet a commitment documented in an inspection report appears to be an isolated cas The inspector had no further comment on this item. This item is closed.

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I (Closed) Unresolved Item 86-01-06: Adequacy of Structural Welding. The lic-l ensee addressed this item as documented in a memorandum from the Recirculation Project Engineering Supervisor dated May 12, 1986. A drywell inspection was conducted to review the structural attachment and integrity of the panels.

l An evaluation of the design and existing supports for the panels concluded that the existing installation was adequate and would perform its design function under expected operating conditions, including a seismic event. The l inspector had no further question regarding the structural integrity of the energy absorption panels.

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The licensee also conducted walkdowns of main steam and feedwater pipe whip restraints in the steam tunnel. This inspection identified no inadequacies l in the as-built configuration (including weld size) when compared to the de-

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Attachment I 4 The inspector reviewed the general quality of welding and structural steel installations associated with safety related systems in the drywell and the main steam tunnel during inspection tours. This area was also reviewed during NRC Inspection 86-02. Based on these reviews, the inspector concluded that the general quality of welding and structural steel installation was accept-able. This item is close (Closed) Unresolved Item 81-15-07: Completion of IEB 79-14 Seismic Analyse The licensee reported in LER 80-12/1T that plant modifications were completed on two supports to correct support deviations from the hanger design detail No further NRC inspection of the field work was completed for supports RHR-H03 and RSW-H168. However, licensee actions to meet the requirements of IEB 79-14 and 79-02 were reviewed in Inspections 85-04, 86-01 and 86-12. The overall program to design and construct piping supports was found acceptable, except that further actions were required to address deadweight supports on seismic Class I systems. These actions have been completed. This item is close (Closed) Unresolved Item 82-23-08: Intake Freeze Protection. The inspector reviewed Plant Information Report 83-02 and noted that the corrective actions implemented by the licensee during the 1983-1985 cold weather seasons were sufficient to preclude freezing in the intake structure bays. Corrective actions included operator surveillance of intake conditions, keeping the in-take track gates clear, use of agitators in the CW bay portable and transfer pumps between the CW and SW bay as necessary to prevent ice formation. These measures were particularly successful during the 1985-1986 cold weather seaso This item is close (0 pen) Follow Item 86-01-11: Hanger Discrepancies Noted in Seismic Reanalysis Program (SRP) modifications. This item was also reviewed in Inspection 86-1 Licensee actions on this item also addressed items identified in Inspection Report 86-04 Licensee actions satisfactorily addressed potential hardware issues. Actions were taken for each item to either correct the discrepancy, or to accept the condition as is following further engineering evaluatio None of the discrepancies were considered significant enough to impact func-tionality of the associated hanger. The disposition of each item is summarized belo CST-H19 - Discrepancies between as-built hangers in the CST pipe trench and r

the hanger isometric detail The hanger as-built conditions were correct but there were errors in the one set of four drawings that detailed 10 support modifications. Individual as-built drawings for each of the 10 supports were prepare RHR-H160 - Space (1/16 inch) between baseplate and ceilin HPCI-HD74B - Space (1/8 inch) between baseplate and wal SW-H79N - Space between baseplate and wall.

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Attachment I 5 Grouting was added behind the baseplate. The inspector reviewed the completea work and identified no inadequacie RSW-H274 - Discrepancy noted between as-built hanger shim and support detai The licensee accepted the shim as is and revised the as-built drawing. Per-sonaal involved with SRP work were instructed to apply the general construc-tion guidance only if specific information is not detailed on the drawin RSW-H250 - Discrepancy between as-built condition and Cygna's as-built support drawin The condition was evaluated in YNSD calculation VYC 430 and determined to be acceptable as-1 SW-H76N - Space up to .153" between baseplates and walls SLC-H37 -

SLC-H37 was accepted as is based on a specific analysi SW-H76N was accepted by inclusion in the category of 4 bolt standard base plate installations that were evaluated on a generic basis and found acceptable when subjected to tension / compression loads onl NRC review of the YNSD evaluation methodology for incomplete contact between baseplates and load bearing surfaces is documented in IR 86-12. The NRC staff found that the methodologies employed were acceptable, and that the engineer-ing evaluations were comprehensive and provided sufficient assurance that results and conclusions were acceptable. Specifically, the evaluations de-termined that the as found support conditions had no impact on support and system operability. However, IR 86-12 contains open items that must be ad-dressed to better document the bases for the corclusions and assure the com-pleteness of the evaluation. One open item concerned the need to complete and better document the walkdowns performed for SRP supports to assure all field conditions were bounded by the cases studied in the generic evaluation The walkdowns were completed. Licensee actions on this item will be reviewed further on a subsequent inspectio A total of 50 supports were reviewed by the resident inspectors - eighteen hangers received a detailed review, and 32 received a general review. The inspector reviewed the above findings in light of the fact that the items were discovered by NRC inspection after the constructor's QC group had accepted the support installation. The inspector concluded that the number and nature of the discrepancies identified by NRC inspection was insignificant in com-parison to the total number of supports modified as part of the SRP program, and in view of the total number of attributes (dozens) on each support in-spected and found acceptable. The overall quality of the support modification program and the completed work was found to be very good. Further, the lic-ensee completed a final QA walkdown of all supports addressed in EDCR 84-402 as part of the design change close out to assure the as-built field conditions

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Attachment I 6 were as reflected in the drawings and design calculations. This close out review and the program for the control of the support modifications was re-viewed during Inspection 86-13 and found acceptabl This item remains open pending completion of the licensee actions for the open items described in IR 86-12 and subsequent review by the NR (Closed) Unresolved Item 85-20-02: Environmental Qualification of Local Power Range Monitors (LPRMs). EDCR 84-427 implemented the modifications to LPRM cabling and connectors with qualified equipment. The components replaced included the under vessel connectors, the drywell cabling, the drywell pene-tration connectors both inboard and outboard, and the reactor building cablin The inspector reviewed EDCR 84-427 and the qualifications for the above men-tioned equipment. No discrepancies were noted. This item is close (Closed) Follow Item 86-01-04: Removal of the Station Service Water (SW) Sys-tem from Service. This item was previously discussed in Inspection Report (IR) 86-04. The inspector concluded the review of the mechanical bypass established during the removal of the SW system in February, 1986. The review included a walkdown of the system and verification of closure of pertinent tagging requests following the licensee's restoration action No deficien-cies were identified. This item is close (Closed) Follow Item 85-30-01: "B" Recirculation loop discharge' bypass valve (V2-548). On September 21, 1985, power was lost to valve (V2-54B) when the fuse blew for the valve control circuitry. Reviews by the licensee determined that the fuse blew as a result of a short circuit caused by chaffing of the wire insulation on a limit switch internal to the valve operator. This chaffing was caused during the placement of the housing cover over the control switches. Rapair actions during this outage were to replace the chaffed wires and regroup the wires internally to prevent damage during the installation of the housing cover. The corrective maintenance perfornied on V2-540 will be verified satisfactory by performance of functional checks per OP 522 The inspector verified the wire used in the rework met environmental qualifi-cation requirements. This item is close (Closed) Unresolved Item 85-02-02: Instrument Channel Interactions. The in-spector noted that instrument channels LT 2-3-73 A and B and PT 2-3-52 C and D remained operable as demonstrated by routine functional testing during Cycle II operations. During the present outage, the licensee determined that the channel interactions were caused by the electromagnatic interaction that re-sulted from the instrument channel signal and relay current carrying conduc-tors running together in the same conduit for about 200 ft. Actions were completed under MR 86-0405 to separate and reroute the cables. Subsequent channel testing per OP 4340 and 4337 showed that the channels were operable and the interaction concern was resolved. This item is close (Closed) Unresolved Item 86-01-03 and Follow Item 85-26-03: Reactor Mode Switch Replacement and RPS "B" Reset Problems. The inspector interviewed licensee personnel and reviewed RPS and mode switch drawings to verify the

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Attachment I 7 licensee's resolution to this item. Actions were completed under MR 86-0179 to tighten loose terminal screws for fuse F21B, which corrected the reset problem identified on January 28, 1986. Actions were completed under MR 86-0207 on February 3,1986 to verify terminal screws were tight on control room panels 9-15, 9-17, 9-32, 9-33 and 9-39, which verified the same problem would not occur in the RPS and ECCS circuit Plant operators experienced problems ~ resetting RPS channel 8 on February 3, v 1986 with the reactor mode switch in the shutdown position. The problem oc-curred while actions were in progress to change out the RPS power suppl Further troubleshooting under MR 86-0241 failed to identify a cause. The reset problem was related to the loss of power supply condition, but this fact was not realized at the time. The RPS B reset problem did not recur and fur-ther investigation from February - May 1986 failed to identify a cause for the problem on February 3,1986. Based on an evaluation completed on May 16, 1986, the licensee concluded the RPS system was operable and acceptable to conduct fuel loading. The licensee also determined that the failure to reset problem was not reportable under 10 CFR 50.7 Following the May 16, 1986 evaluation and based on reviews of events on June 10-11, 1986, the licensee determined that as a result of circuit modifications made unoer PDCR 85-03, a problem resetting a half scram could occur under certain conditions, i.e., with the mode switch in shutdown and a loss of power or de-energization of the RPS channel. Interim and long term actions were taken to address this potential problem, as described in Section 5. The licensee also evaluated the operation of the reactor mode switch (SA-51 Type SB-1) during the review of scram system anomalies. A question that arose during the post-replacement functional test of the mode switch (Item 85-26-03)

was satisfactorily resolved following further consultation with GE. The lic-ensee determined that mode switch drawing 5920-2119, Revision 19 (730E365 Sheet 6) was incorrect in the contact arrangement shown for the switch in the intermediate position between startup and run. The mode switch does not make-before-break or break-before-make in the intermediate positions. This feature was confirmed by inspector observation of the contacts during switch operatio Actions were taken to obtain updated mode switch drawing information from the

vendor and to complete corrective updates on other plant drawings. Based on this information, the licensee concluded that the mode switch was functioning properly, and thus, operable.

l l Based on the above, the inspector determined that all hardware issues associ-ated with operation of the mode switch and the scram reset feature were re-solved. These items are closed.

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, (Closed) Follow Item 84-21-02: Control Rod 18-11. The control rod and drive l

mechanism at core location 18-11 were examined during the 1985/86 refueling outage. No adverse conditions were identified that would present the rod from moving out to position 4 The control rod will be used for cycle 12 opera-tion and a rebuilt drive has been installed for the rod. Control rod 18-11

, will be tested as part of the reactor startup program. The testing included i coupling checks, function tests and scram test. This item is closed.

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Attachment I 8 (Closed) Unresolved Item 86-01-10: Control of Contractor Activities. The discrepancies observed by the NRC inspector were reviewed by the licensee and addressed in a memorandum from the maintenance supervisor dated May 1, 198 The lapse in the thermocouple calibration was first noted by the contractor

and would have been addressed without QC involvement. The welder certifica-tion was correct and the missing signature was a documentation discrepanc The valve seat material was incorrectly identified initially which caused the wrong welding procedure to be submitted for approval. The material was cor-rectly identified by the contractor upon disassembly of the valve and the appropriate procedure was reviewed by the licensee prior to starting the wor Additionally, future activities by this vendor will receive QC inspection to resolve any inconsistencies and 0QA surveillance. This item is close (Closed) Violation 86-05-01

Inoperable SLC Syste This item was addressed in IR 86-08. The licensee's response to the violation was submitted in letter FVY 86-43 dated May 22, 1986. Licensee actions in response to the violation were reviewed, including actions to retest the SLC system to verify operabil-ity prior to reloading the core. Licensee actions were consistent the com-mitments made in FVY 86-43 and during the March 19, 1986 meeting, as docu-mented in the April 15, 1986 Enforcement Conference Report for 86-0 Test procedure OP 4203, Revision 8, was revised to change the method for test firing the squib valves, and to check the pin-to pin continuity of the primer as a pre-service verification of the bridgewire wiring. The inspector re-viewed the test activities on May 8 and 9, 1986. The tests verified that the valves to be used for Cycle XII operations were operable and compatible with the VY installation. During the test on May 8, 1986, the "A" SLC pump tripped upon system initiation due to a failure in the breaker trip setting. The SLC full flow test using the "A" pump was completed satisfactorily per OP 4114 on May 9,1986 after the pump breaker was investigated and replaced under MR 86-92 The inspector reviewed other licensee actions in response to the violation, including: revision to drawings B191301 Sheets 1200 and 1201, and other CRP 9-5 panel drawings; completion of purchasing enhancements, including receipt of component drawings; a QA evaluation of the vendor by YNSD, and the comple-tion of a review of the remaining primer charges to assure only those within the established shelf life intervals were kept in Stores; and, a review of surveillance practices on other plant safety systems. The licensee determined that, with the exception of the TIP system (discussed further below), no other surveillance test performed an after-the-fact operability demonstration on the associated safety system. Actions were completed per MR 86-524 to rewire the squib valve local terminal box to agree with the design drawing The licensee completed an evaluation of the continuity monitoring circuit and concluded that no circuit modifications were warranted based on the ccnfigura-tion control procedures in effect and the enhancements made to the functional test procedure. The inspector noted, based on a review of control room indi-cations and knowledge of plant systems, that no safety systems other than SLC and the TIP system relied on a continuity monitoring circuit for any explosive-activated device. Based on the above, the licensee's actions were acceptabl O

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Attachment I 9 The licensee determined that enhancements similar to those made for the SLC system were also appropriate for the functional test of the TIP shear valves, implemented by Procedure OP 5334 Revision The inspector verified that the TIP valves were tested satisfactorily per the revised procedure on June 14, 198 The inspector noted that during the test, the in situ firing of the primer charge scheduled for removal from the #3 TIP was not completed because the primer connector was damaged while setting up for the test. The connector was replaced and the in situ test on the new primer charge from the batch to be used for Cycle XII was completed satisfactorily in the #3 firing circui No inadequacies were identifie Based on the above, the inspector determined that the licensee's actions were acceptable to assure operability of the SLC system and the TIP isolation sys-tem prior to entering a plant operational mode for which the systems were required to be available. Inspection item 85-06-01 is close The inspector noted that two programmatic questions remain outstanding, in-volving the results of the QA review of the squib valve vendor, and the need to enhance the SLC testing requirements in the technical specifications. In FVY 86-43, the licensee stated that the need to revise SLC surveillance specifications will be considered, and if deemed appropriate, the changes to the specifications will be made in time to support the next SLC operability test scheduled for the 1987 refueling outage. The Plant Manager stated that a proposed technical specification change request has been drafted and is under review. This item is unresolved pending completion of the licensee's actions and subsequent review by the NRC (UNR 86-10-12). (0 pen) Unresolved Item 86-08-01: Cooling Towers. The inspector interviewed

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licensee personnel, reviewed completed design change and work packages, and

toured the cooling towers. Modifications were completed on the towers by June 23, 1986 which restored Cells Nos. I and 2 to a configuration that was

within the scope of the current seismic analysis. Thus operability of the alternate (ultimate) heat was assured prior to plant restar .

The licensee provided information for NRC review regarding his determinations on the reportability of the incident and the seismicity of the towers during the 1980-1985 time period. An evaluation of the towers with the "E-fixes" in place showed that the seismicity of the structure was not significantly affected. The licensee concluded based on the assessment documented in PRO 86-20 dated April 4,1986 that the item was not reportable per 10 CFR 50.7 This item remains unresolved pending further NRC review of the PRO and the results of the seismic analysi (Closed) Follow Item 86-05-08: Shelf Life Control of Squib Primers. The lic-ensee completed a review of Conax charges in the storeroom and segregated those that could not be used prior to expiration of the shelf life. The in-spector witnessed bench firing of the excess charges in the maintenance shop on May 19, 1986. This item is close .

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Attachment I 10 (Closed) Follow Item 86-05-07: TIP Shear Valves. The SLC test improvements were applied to the TIP shear valves, as discussed in item V above. This item is close (Cicsed) Follow Item 86-05-06: PIR 8G-01 Recommendations. The inspector re-viewed the final version of PIR 86-01 dated March 17, 1986 and noted that the final recommendation and conclusions were consistent with the preliminary version and the commitments made in FVY 86-43. This item is close A (Closed) Follow Item 86-05-05: Maintenance of the Continuity Monitoring Cir-cuit. This item was addressed during the meeting on March 19, 1986 and during followup discussion with licensee personnel. The licensee determined that the circuit is not sensitive to current imbalances, and further, that changes made per SIL 186 recommendations will assure that the circuit will function as designed when the intended configuration is maintained. The inspector noted that monitoring circuit problems are most usually attributable to burned out light bulbs in the control rela This condition is alarmed in the con-trol room and backup indication of circuit continuity is available in the control room back panels to verify the bridgewire firing path is intac Based on the above, the inspector identified no further issues on the con-tinuity monitoring circuit that warranted further investigation. This item is close B (Closed) Unresolved Item 86-05-04: SLC Configuration Control. This item was addressed as part of item 86-05-01 and was discussed during the March 19, 1986 meeting. The NRC staff concurred with the licensee's conclusion that the SLC circuit configuration control was not lost upon implementing the 1977 design change, since the SLC firing circuit was left in an operable configuration for the type of primer supplied at that time and successfully tested for the subsequent seven years. The NRC staff concurred with the determination that the primary cause for the inoperable SLC system was the subsequent manufac-turing error in the primer charges. Additional concerns regarding the need to assure the as-built design change conditions are cccurately reflected in the design drawings was adequately addressed in the response to inspection l item 86-05-01 (reference FVY 86-43). This item is close C (Closed) Follow Item 86-05-03: Continuity Monitoring Circuit Design. This item was discussed during the March 19, 1986 meeting and was reviewed in re-sponse to inspection item 86-05-01. The licensee determined that the SLC monitoring circuit design will function as designed provided the electrical installation configuration of the firing circuit is maintained per the design drawing Existing administrative procedures for system electrical configur-

ation should assure configuration control occur This item is closed.

l D (Closed) Unresolved Item 86-05-02: Conax Manufacturing Error. Subsequent in-formation submitted by the Conax Corp. (Reference: NRC Information Notice 86-13) confirmed that a manufacturing error resulted in the delivery of primer charges with a pin-to-bridgewire firing circuit different than that specified l by the design drawings. Additionally, in response to item 86-05-01, the lic-

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Attachment I 11 ensee stated that design drawings will be obtained for subsequent purchases of the squib valves, and the drawings will be reviewed for changes prior to use of the valves. This item is close E (0 pen) Unresolved Item 86-08-04: Stability Monitoring. Subsequent review of this item with NRC:NRR determined that Single Loop Operation technical spect-fications are not required and will not be issued to begin Cycle XII opera-tions. Cycle XII operations will be constrained by the present technical specifications which restrict operation with only one recirculation pump to less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Additionally, stability monitoring will be conducted in accordance with the guidelines in NRC Generic Letter 86-02. The licensee's proposed procedures for stability monitoring and single loop operations were reviewed by a Region I specialist. The proposed procedures were found ac-ceptable pending completion of actions to address comments provided by the inspector to licensee personnel during an inspection on June 23, 1986.

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One comment of particular importance concerned the need to better define in OP 2427 the region of the power to flow map where baseline stability data would be obtained. The licensee concurred that the data should be obtained from the most unstable region, that region closest to the minimum pump speed line (i.e., near to the natural circulation line) and the 100% rod lin The licensee stated that criteria would be incorporated in OP 2427 to define the test regio Licensee actions to monitor core stability will be followed on a subsequent routine inspectio F (Closed) Unresolved Item 86-01-02: Defects in NAMCO Contact Blocks. The in-spector interviewed licensee personnel and witnessed actions taken to assure only acceptable electrical contact blocks and carriers were installed in plant safety systems. The licensee completed actions to inspect and replace as necessary the contact blocks and carriers on the main steam isolation valves (32 switches) and on the turbine stop valves (4 switches). NAMCO switches are not used in other safety related circuits. Actions to inspect and replace the components were docu: rented in QC Inspection Reports IC 86-97, 98 and 128.

j The NAMCO bakelite components in stores were also reinspected to assure all

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defective components were removed.

, Subsequent licensee followup included the following three corrective actions.

l (1) New inspection procedures were developed to complete pre-installation in-

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spections of contact blocks and carriers for crack and chip defects of the type previously identified. Alignment of the contact faces was added as an inspecticn attribute after receipt inspections on new replacement parts on

, May 23-24, 1986 identified questionable alignment of the contact mating sur-l faces. Additional design specification and inspection criteria information

[ was obtained from the vendor to assure that only acceptable parts were sub-sequently installed in the safety circuits. (2) A May 8, 1986 visit to the l

! vendor's manufacturing facility was conducted to complete a joint evaluation of the components with defects removed from the VY switches and Stores. And,

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(3) YNSD QA completed a vendor visit and surveillance to review QC and pack-l aging controls.

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Attachment I 12 The evaluation of defective parts (13 total) removed from plant components and the storeroom resulted in the following determinations: (1) The crack defect on the block removed from the 86B MSIV " shut" position indication switch was determined to have occurred during installation. (2) Two parts with crack defects taken from Stores were evaluated to be non-functiona (3) Of the remaining ten components with chips or cracks, four had insignifi-cant defects that the vendor felt would pass QC inspection at the factor (4) Two blocks from the remaining six which were considered to have the worst case defects were selected for further testing. The components passed an arc suppression test completed by applying a 1000 Vac to terminals adjacent to defects for ten seconds while continuity was checked. The tested parts were found functional, since the test conditions bound the circuit application for the components at VY (120 Vac and 125 Vdc with operating currents of 250 mA and 100 mA, respectively).

The bases for the engineering conclusions in the licensee's March 28, 1986 Part 21 report concerning the unacceptability of the defective parts was re-viewed with YNSD. The licensee stated the conclusions reached concerning the possible consequences of using the defective parts was a " conservative" call that was made based on an engineering assessment, and not as the result of either testing or an engineering evaluation of the defects / failure mod Basec on the above and licensee actions to install new parts without any known defects in plant systems, the inspector determined that the licensee's actions were acceptable to declare the associated safety systems operable. The in-spector noted that the contact blocks and carriers were subsequently installed and energized in the associated circuits and functionally tested satisfactor-ily without problems. Inspection item 86-01-02 is considered close Continued NRC staff review of the programmatic questions raised by this item will be tracked by: (i) violation 86-08-06 regarding the licensee's improper l control of potentially defective materials; and, (ii) inspection item 86-08-05

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regarding additional NRC review of the vendor QC controls and the potential generic applicability of the issue to other users of the component G (Closed) Follow Item 85-39-03: TIP System Indexing. The inspector noted that licensee actions were completed prior to startup to install and calibrate the new TIP crives. The inspector interviewed licensee personnel and reviewed actions to assure the TIP detectors would be parked in the shielded position after removal from the core. This item is closed. The need to document the j instructions and steps taken to assure the detectors are parked in the shielded position was discussed with the licensee and the plant manager, and is followed as an inspection item in report IR 86-1 HH. (Closed) Unresolved Item 86-01-08: Hydrogen-Oxygen Analyzers. The licensee's evaluation for the event was reported in LER 86-02, which included a descrip-tion of the actions to correct the discrepant condition. The inspector noted during discussions with I&C personnel that actions were in progress to in-stall new components in both analyzer trains prior to startup from the outag The rebuild kits included new elastomers in the diaphrams for both system l

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Attachment I 13 sample pumps and the 22 solenoid operated valves. The materials will make the components environmentally qualified for the newly defined radiation ex-posures limits provided by YNSD engineerin Item 86-01-08 is considered closed for tracking purposes on the basis of the completion of licensee actions to address the hardware discrepancies. How-ever, further NRC staff review is required of the cause, and potential con-sequences of the event, as described in the LER 86-02. This item is unre-solved (UNR 86-10-13).

I (0 pen) Violation 86-12-02: Documentation of Weld Inspections. This item con-cerned the documentation of QC inspection of the final structural welds for whip restraints R6A and R98, which was provided on the weld history cards and not per procedure FQP- This status of actions on this item was reviewed with the QA Supervisor for the Recirculation Task Force on May 22, 1986. The licensee's review and re-solution for this item was documented in Morrison and Kundsen Nonconformance Report 237. The licensee reported that the scope of work inspected and docu-mented under the wrong procedure was identified. Structural welds were ac-cepted as is if the weld history card referenced the appropriate accept / reject criteria. Otherwise, completed work was reinspected and the required docu-mentation was completed. The licensee stated that documentation of the QC inspections on the weld history cards, while wrong per the procedural require-ments, was acceptable since most inspection attributes in procedure FQP- are not applicable to structural welds. No material deficiencies were iden-tified as part of the NCR closecu This item remains open pending receipt and subsequent review of the licensee's response to the violation.

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O ATTACHMENT II Summary of Licensed Operators Interviews Interviews were held in the resident inspector's office except for persons working at the Brattleboro training center and corporate headquarters. Those people were interviewed at the training cente Interviews lasted an average of a half hou All interviewees were asked to comment regarding: (1) a description of emergency operating procedures (EOP) training they had received, (2) positive and negative attributes of the training received, (3) comparison of training on Dresden and VY simulators, (4) comparison of old and new E0P formats, (5) their level of under-standing of the E0Ps, (6) any reservations about implementing the E0Ps, (7) need for additional training on E0Ps, (8) discussion of concerns about E0Ps with VY management or the NRC and (9) quality of training on modifications implemented this outag The interviewees described the training they received on E0Ps. It consisted of classroom and simulator training. Training received at the Dresden simulator early in 1985 lasted only a few days and because of the condition of the new E0Ps at the time, the training was generally considered insufficient. The E0Ps apparently contained numerous errors, were difficult to follow, and were unfamiliar to the operator As a result of operator complaints to their management and allegations to the NRC, the original implementation date for the E0Ps was delayea from June 1985 to the end of the present outage. In addition, all crews were given a week of additional simulator and classroom training at the Dresden simulator in the Fall of 198 Following that training, the GE training instructor and his manager prepared and sent written evaluations of each crew's performance to the VY Operations Supervi-sor. These evaluations were very brief, and in some cases only a few words. At the end of that training, all of the operators indicated they were capable of using the E0Ps and that the E0Ps can be implemented.

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! Subsequent to that time, all crews have gone through training on all aspects of l two E0Ps and parts of the other four E0Ps, using the VY simulator. Training on

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the remaining aspects of the four E0Ps will be conducted in the next cycle of training to be completed following startup, which should be done by early August 198 Interviewees were very positive about the training received, particularly the five

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days last Fall. They believed it enabled their understanding and appreciation of

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the new symptom oriented flow diagram E0P Several would have preferred the training be on the VY simulator but considered the Dresden work acceptable. Only

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I a few considered the differences between Dresden and VY significant. They were l all aware of the upcoming training using the VY simulator and felt that it would be beneficial.

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Attachment II 2 Many of the operators suggested increased use of the VY simulator for routine training evolutions such as startup, power escalation, placing the turbine on line, power changes, turbine trip, reactor scrams, and other routine events with causal-ity events requiring use of E0Ps interjected after a period of routine, perhaps even boring activitic This would be more realistic training for the E0Ps rather than concentrated work on just E0Ps where the unexpected is expecte A few senior operators believed that some additional training, particularly for the less experienced operators may be desirable, especially training on routine events. It was interesting to note that one senior operator had never actually experienced a real scram at the plant. He noted that practice on the VY simulator would be good for hi Not one of the people interviewed would voluntarily go back to the old narrative written procedures. They were all enthusiastic about the many advantages of the new symptom oriented flow chart procedures. They felt they were easier to follow, easier to re-enter and find your place, end points and consequences are more ap-parent, and the wholc sequence of possible actions and reactions are laid out in front of yo The operators felt that they understood and knew how to use the new E0Ps. Only one indi.vidual seemed slightly unsure of his position, and he was identified to VY management. The VY Plant Manager committed to pay attention to that indivi-dual's capabilities during the walkthrough drills of shift crews to be conducted prior to their operating the plant during or after the next startup. The other operators didn't have any reservations about their being implemented at the end of this outag Most of the operators said that they would like to have more training on the VY simulator. No one indicated they didn't have enough VY simulator training to dat They were all aware of the upcoming additional VY simulator training and with a few exceptions were looking forward to it. A few indicated "we have had too much E0P training already."

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Not many commented on the details on the training received on the modifications completed this outage. All indicated that the training was acceptable. All felt free to go to VY management, as had been done early in 1985, or to anyone in the

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NRC if they experienced problems in the future of this kind.

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o ATTACHMENT III The following is a listing of references and procedures reviewed to verify licensee administrative controls for restoration and startup activities were followed.

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Core Loading Fuel Load Punchlist OP 4318, Mode Switch Functional Test J/LL 86-96, SRM Interlocks Technical Specifications 3.5 and 3.12 OP 1410, Fuel Loading Schedule OP 4420, SRM Response Checks S+TO 86-750, Core Spray Interlocks OP 1410.02, Refueling Prerequisites OP 1490, Refueling Radiation Work Permits 86-4350, 4068, and 4348 System Valve Lineups per OP 2123, 2114, 2182, 2117, 2116, 2111, 2181 Surveillances per OP 5312, 4346, 4347, 4348, 4349, 4114, 4203, 4611, 4111, 4310, 4318, 4326, 4317, 4300, 4117, 4332, 4335, 4181, 4306, 4326, and 4116 Startup Startup Punchlist OP 5335, TIP Shear Valve Testing OP 4100, Integrated ECCS Test OP 4101.1, Class 1 Hydrostatic Test OP 0100, Reactor Startup to Criticality OP 0101, Reactor System Heatup to Low Power OP 0100.01, Reactor Startup Prerequisite List, inspected June 3 and June 30, 1986 System Valve Lineups per OP 2123, 2124, 2120, 2121, 2117, 2114, and 2181

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