ML20056C972

Insp Rept 50-271/93-13 on 930523-0626.Violation Noted. Unresolved Item Opened Re Contaminated Equipment Control. Major Areas Inspected:Plant Operations,Radiological Controls,Maint & Surveillance & Security

ML20056C972
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	07/21/1993
From:	Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20056C970	List: ML20056C968 ML20056C971 ML20056C972
References
50-271-93-13, NUDOCS 9307300170
Download: ML20056C972 (65)

See also: IR 05000271/1993013

Text

{{#Wiki_filter:-. _ __ . . U.S. NUCLEAR REGULATORY COMMISSION REGION I Report No. 93-13 , Docket No. 50-271 Licensee No. DPR-28 q Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169 ) Ferry Road Brattleboro, VT 05301 Facility: Vermont Yankee Nuclear Power Station i ~ Vernon, Vermont Inspection Period: May 23 - June 26,1993 Inspectors: Harold Eichenholz, Senior Resident Inspector Paul ' Harris, Resident Inspector 7 3 ~ Approved by: - - Eugene M. Kelly, Chief Date Reactor Projects Section 3A Scope: Station activities inspected by the resident staff this period included: plant operations; radiological controls; maintenance and _;urveillance; security- engineering and technical support and safety assessment and quality l verification. An initiative selected for this inspection was simulator training 1 for control room operators. Backshift and " deep" backshift including weekend ' activities amounting to 21 hours were performed on May 25, 26, 27, June 6, I 8,9 and 14. Interviews and discussions were conducted with members of i Vermont Yankee management and staff as necessary to support this inspection. Findings: An overall assessment of performance during this period is summarized in the Executive Summary. A violation involving improper calibration of the core spray sparger pressure differential instruments was identified (Section 4.2.1). Enforcement discretion was exercised for the failure to properly leak rate test the containment atmospheric sampling system (Section 6.1). An unresolved item was opened (Section 3.2) regarding contaminated equipment control. i 9307300170 930722 P PDR ADOCK 05000271 l' G PDR y

. - . _ _ _ - _ _ _ _ _ _ _ - t e , . EXECUTIVE SUMMARY Vermont Yankee Inspection Report 93-13 i ' Plant Operations Conservative actions were implemented to minimize fuel stress, in response to indications of a minor fuel element failure. Simulator training for control room operators was effective. Radiological Controls f Several instances reflecting poor radiological work practices were observed. A lack of sensitivity to the potential for internal system contamination was demonstrated during l maintenance on a standby gas treatment filter. Surveys were not performed for potentially changing radiological conditions during testing. Vermont Yankee identined ineffective control of contaminated equipment at an offsite storage facility. i Maintenance and Surveillance

Effective planning and maintenance was performed on three safety-related systems. Improved work package development and attention to detail were observed. Concern over i Vermont Yankee's root cause evaluations for the residual heat removal service water 89A valve failure involved limited documentation of "as-found" conditions. Evaluation of industry experience and biennial technical review of procedural adequacy failed , to identify a long-standing setpoint problem for core spray sparger pressure instruments, resulting in a violation of Technical Specifications. Engineering and Technical Support Appropriate corrective actions were implemented to leak rate test the containment hydrogen / oxygen monitoring system. Adequate Emergency Operating Procedure review and operator training were conducted for potential reactor water level instrumentation errors during and after reactor depressurization. .: i ii ___

. TABLE OF CONTENTS . . t EXECUTIVE SUMMARY ......................................ii TABLE OF CONTENTS .......................................iii 1.0 SUMMARY OF FACILITY ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . I 2.0 PLANT OPERATIONS (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I 2.1 Operational Safety Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l ' 2.2 Rod Pattern Adjustment 2 ............................... 2.3 Evaluation of Reactor Offgas Release Rates . . . . . . . . . . . . . . . . . . . 2 l 2.4 Control Room Operator Training . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ! 3.0 . RADIOLOGICAL CONTROLS (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . 3

3.1 Radiation Surveys in Support of Plant Maintenance . . . . . . . . . . . . . . . 3 , 3.2 (Open) URI 93-13-01: Contaminated Equipment Control . . . . . . . . . . . 4 3.3 Radiological Surveys During Changing Plant Conditions 4 ...........

i 4.0 MAINTENANCE AND SURVEILLANCE (62703, 61726) . . . . . . . . . . . . . . 5 4.1 Maintenance ..................................... 5 ' 4.1.1 Failure of Service Water Valve Anti-Rotation Key . . . . . . . . . . . 5 4.1.2 Standby Gas Treatment - LCO Maintenance . . . . . . . . . . . . . . . 6 4.1.3 Circuit Breaker Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 7 l 4.2 S urveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4.3 (Open) VIO 93-13-02: Core Spray Sparger Break Detection - Nonconservative Setpoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 1 5.0 SECURITY (71707, 92700, 93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . I1 . k 6.0 ENGINEERING AND TECHNICAL SUPPORT (71707,62703) I1 ......... 6.1 Appendix J Testing: Drywell Hydrogen / Oxygen Monitoring System 11 ... 6.2 Water Level Instrumentation Errors During and After Depressurization

Transients (TI 2515/1 19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 ' i 7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (90712. 90713, 92700) 13 ............................................. 7.1 Periodic and Special Reports 13 ........................... 7.2 Licensee Event Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . ! 8.0 MANAGEMENT MEETINGS (30702) 14 ......................... 8.1 Preliminary Inspection Findings 14 .

......................... ' 8.2 En forcement Conference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Note: Procedures from NRC Inspection Manual Chapter 2515 " Operating Reactor Inspection Program" which were used as inspection guidance are parenthetically listed for each applicable report section. , I 111 1 6

. .. !

l ~ DETAILS 7 1.0 SUMMARY OF FACILITY ACTIVITIES

Vermont Yankee Nuclear Power Station was operated at full power during this inspection ' period. On June 6, the licensee (or VY) reduced power to 65 percent for a rod pattern adjustment and single rod scram testing. Results of this testing were within Technical l Specification (TS) requirements for both core average and 2 x 2 arrays, and did not indicate ! any abnormal trend. ! A delegation of representatives from Eastern European nuclear regulatory bodies, who were , in the United States as part of NRC-sponsored training, visited the site on June 14-15. The . i delegation also observed the conduct ofinspections associated with the NRC Operational Safety Team Inspection performed on site during this period. t t f During May 10 to June 11, the Operations Superintendent participated in the INPO sponsored Senior Nuclear Plant Management Course. 2.0 PLANT OPERATIONS (71707) ' 2.1 Operational Safety Verincation , j This inspection consisted of direct observation of facility activities, plant tours, and operability reviews of systems important to safety. The inspectors verifi ,' that the facility l was operated in accordance with license requirements. Plant operations . ere observed i ' daring regular and backshift hours in the control room, reactor building, cable spreading room, and emergency diesel generator rooms. Daily, the inspectors verified that emergency core cooling systems (ECCS) were properly aligned for automatic initiation. Field

inspections confirmed that ECCS pumps and valves were configured as indicated on control i room panels, material conditions were good, and housekeeping was commensurate with work in progress. , l The inspectors toured the perimeters of both the secondary and primary containments to verify system integrity. Torus water level and temperature process connections, and a sample of penetration welds for systems connected to the suppression chamber, were visually inspected using OP 4115, Rev. 29, " Primary Containment Surveillance," as a pide. No corrosion or porosity was observed on the inspected welds and no discrepancies were { , identified. The inspector also verified that the surveillance of the torus vent system was j properly performed. During the walkdown of the secondary containment, the inspectors i verified that truck door seals were properly inflated, reactor building ventilation ducts were . intact, and personnel access doors were properly sealed. Of the areas inspected, all air leakage was in-leakage and no degraded containment material conditions were identified. Control room and shift manning were in accordance with TS requirements. Control room instruments correlated between channels and were verified to properly trend during surveillance and/or system operation. In addition, plant parameters displayed on the 1 . -- - - -- ,,

_ _ _ _ _ _ _ _ _ - _. _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ __ _ ____ . . . . . . 2 Emergency Response Facility Information System (ERFIS) also correlated well with plant instruments. Control room operators were observed to effectively use ERFIS in the identification of trends, status of single rod scram testing, and turbine valve surveillances. Alarms received in the control room were reviewed with respect to the alarm response requirements, discussed with operators, and verified to be adequately documented in control room logs. Control room operators were knowledgeable of ahrm conditions and single rod scram testing. 2.2 Rod Pattern Adjustment On June 6, the inspector conducted " deep" backshift (between 10:00 p.m. and 5:00 a.m.) inspection to observe the conduct of operations during a planned rod pattern exchange. In accordance with Operations Department night orders and Reactor and Computer Engineering Department guidance, control room operators decreased power to 65 percent. During scheduled hold points, surveillance testing was performed in accordance with procedures OP 4424 and OP 4160 to verify the operability of all control rods, main steam isolation valves, and turbine bypass valves. Single rod scram testing on 45 of 89 control rod drive mechanisms was performed, and the following average insertion times were achieved: 45 rod average - 0.320 secs Previous 89 rod average - 0.312 secs 89 rod average - 0.312 secs TS limit - 0.375 secs. All testing performed met TS requirements. Control room operators demonstrated knowledge of the surveillances performed, and test results were promptly evaluated. Approved procedures were in use and appropriate shift augmentation was provided to facilitate safe plant operation. Surveillance testing was performed sequentially and subsequent testing was not commenced until previous test results were evaluated. Operators were attentive to duty and focused on the task at hand. The shift turnover was accomplished

I such that current plant conditions were understood by the on-coming shift. I 2.3 Evaluation of Reactor Offgas Release Rates Following the rod pattern adjustment on June 6, reactor power was increased to 100 percent whereupon subsequent offgas analyses indicated a small fuel rod failure. This determination was based on an analysis of the isotopic concentration of the offgas sample and confirmed by both Yankee Nuclear Services Division and General Electric. Vermont Yankee has preliminarily concluded that a very small pinhole or crack exists within one fuel rod. Significant changes in the offgas radioactive concentrations have not been observed, as instantaneous offgas values continue to be in the 19,000 to 21,000 pCi/sec range. Licensee management implemented conservative power ascension rates to minimize fuel element stress, and implemented a plan to reduce the number of future rod pattern adjustments to further minimize the number of power-cycles on the fuel. These actions were more conservative than those required by the existing Failed Fuel Action Plan. j .. . _ _ - _ _ _ _ _ _ _

_ _ . _ _ . - , 3 2.4 Control Room Operator Training On June 4, the inspector observed simulator training for control room operators. Operators responded to two sequential and challenging plant transients: one involving a recirculation line break that required reactor pressure vessel emergency depressurization and flooding, and ~ the other, an anticipated transient without scram with an electrical bus failure. Both scenarios were evaluated and graded by the VY training staff using NRC examiner standards. The operators correctly diagnosed plant conditions and responded in accordance with ' Emergency Operating Procedures (EOPs). Actions were timely, EOP entry conditions were recognized and properly evaluated, and operators demonstrated proficiency at the controls. - Communications were accurate and succinct. Event notifications met regulatory requirements. The simulator critique performed by the VY training staff was also effective. Crew performance strengths and weaknesses were itemized and the post 4 rill brief was candid and focused on each observation. The critical tasks / steps accurately paralleled the scenarios and were individually assessed. The training staff did not interject or direct crew actions, and the Operations Training Supervisor independently evaluated the operating crew and training staff. 3.0 RADIOLOGICAL CONTROLS (71707) Inspectors routinely observed and reviewed radiological controls and practices during plant tours. The inspectors observed that posting of contaminated, high airborne radiation, radiation and high radiation areas were in accordance with administrative controls (AP-0500 series procedures) and plant instructions. High radiation doors were properly maintained and equipment and personnel were properly surveyed prior to exit from the radiation control area (RCA). Plant workers were observed to be cognizant of posting requirements and maintained good housekeeping. Several exceptions to these routine observations occurred, as discussed below. 3.1 Radiation Surveys in Support of Plant Maintenance During this period, the inspector selected two work activities to verify the proper performance of radiation surveys: (1) insulation replacement for the residual heat removal service water (RHRSW) system; and (2) maintenance / surveillance for the standby gas treatment (SBGT) system (Section 4.1.2). Radiation and contamination survey maps were reviewed, field inspections were conducted, and workers were interviewed at the work site to assess their knowledge of existing radiological conditions. In both activities, workers were knowledgeable; radiation and contamination levels were minimal, and radiation surveys were necessary prior to start of work and work scope increases. Appropriate airborne monitoring . for iodine and radiological boundaries / postings were implemented.

, h jobs 4 sonnel associated with t einternal ing the The c on the SBGT system, peritivity to the potential li of ity stated that the probabi ty . o high efficiency maintenance carbon trayswho bserved this activ During thedemonstrated a lack of sens / s because an pstreamof the trays. Both th RP u f the o removal and handling o P) technician w based on past RP survey , ination he inspector's concern t ahould ntil proven radiation protection (R would prevent contam was lo Manager later acknowledged t contamination filter u tream HEPAcontamination lothing, particulate air (HEPA) c i lly contaminated system s er square s on the integrity of the pdid not speci0cally requirele technician and RP components of a potent awork permit for this liance otherwise, and that re occurred. i on events The radiation although subsequent survel contaminn Control material outside j centimeter, and no actua Contaminated Equipment d tified radioactive torage facility, 1 (Open) URI 9313 0 :ly RP surveillance, VY i en Company offsite quipment s VY. Four e support activities at i n cord, and air hose)xcee 3.2 Mercury tion On May 25, during a quartercontrol area (RCA) in amaintenanc wer supply cord, extens od for free ntly, a the radiationCompany performs were transported back tocontaminat i der, welder po i n levels above that require Mercurywere identified (a gr n i ms a spot check and identexceed tivelimits. Tnese te p of the its that had contaminat ocontamination adminis determine the isotopic makeu items Vehicles, to perform y and Release f Materials,VY's ) which also was sent to the facility analyses performed to o tape, and scaffolding occurrences involvingC ere documented in NR diation Control Area." Prevdure AP second survey team surveillance sample s additionalitems (air hose, ious release from the RCA wd whether the specified in plant proce a of ent prior toThe inspector also questionel as and Trash from the Ra adequately survey equipm representatives indicateld be ddre h ir Inspection Report 92-09. ugh to provide reasonab e (URI 93- Yankee VY were discussed with ansubseq was sufficiently large enowere stored offsite.ys in th a Vermont ented by reviewed during a corrective actions implemi list and will be thoroughness of surve items action. Theradiation protection pec a Conditions s ing Changing Plant coolant injection ed that for the high pressuretheinspec 13 01). Radiological Surveys Dur o u of quarterly surveillancescooling (RCIC) syst the hanging radiation hnician dispatch 3.3 valve packin isolation operation. An RP tec During the performance c not performed to monitor surveys for tio (HPCI) and reactor core contaminationfile, and found n HPCI and RCIC pump turbine were was bserved performingi wed the R radiation surveys of reactor team for o s s to the surveillance arealeakage. The inspector of a sun ey. erformance that substantiated the p x ~ ^N 'ww

. . 4 During the maintenance on the SBGT system, personnel associated with the jobs demonstrated a lack of sensitivity to the potential for internal contamination during the removal and handling of the carbon trays without the use of anti-contamination clothing. The radiation protection (RP) technician who observed this activity stated that the probability of contamination was low based on past RP surveys, because an upstream high efficiency particulate air (HEPA) filter would prevent contamination of the trays. Both the RP technician and RP Manager later acknowledged the inspector's concern that the internal components of a potentially contaminated system should be treated as such, until proven otherwise, and that reliance on the integrity of the upstream HEPA filter is inappropriate. The mdiation work permit for this job did not specifically require contamination clothing, although subsequent surveys indicated contamination levels less than 1000 dpm per square centimeter, and no actual contamination events occurred. 3.2 (Open) URI 93-13-01: Contaminated Equipment Control On May 25, during a quarterly RP surveillance, VY identified radioactive material outside the radiation control area (RCA) in a Mercury Company offsite equipment storage facility. Mercury Company performs maintenance and modification support activities at VY. Four items were identified (a grinder, welder power supply cord, extension cord, and air hose) that had contamination levels above that required for free release; all items exceeded fixed contamination administrative limits. These items were transported back to the RCA and analyses performed to determine the isotopic makeup of the contamination. Subsequently, a second survey team was sent to the facility to perform a spot check and identified three additional items (air hose, tape, and scaffolding) which also exceeded the release limits specified in plant procedure AP 0516, Rev 3, " Survey and Release of Materials, Vehicles, and Trash from the Radiation Control Area." Previous occurrences involving VY's failure to- adequately survey equipment prior to release from the RCA were documented in NRC Inspection Report 92-09. The inspector also questioned whether the surveillance sample size was sufficiently large enough to provide reasonable assurance that no additional contaminated items were stored offsite. Vermont Yankee representatives indicated that the question of thoroughness of surveys in the offsite facility would be addressed as part of their corrective action. The corrective actions implemented by VY were discussed with an NRC Region I radiation protection specialist and will be reviewed during a subsequent inspection (URI 93- 13-01). 3.3 Radiological Smveys During Changing Plant Conditions During the performance of quarterly surveillances for the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems, the inspector observed that radiation surveys were not performed to monitor the changing radiation fields due to the use of reactor steam for HPCI and RCIC pump turbine operation. An RP technician dispatched to the surveillance areas was observed performing contamination surveys for valve packing leakage. The inspector reviewed the RP log and survey file, and found no documentation that substantiated the performance of a survey. o

. . 5 A contributing cause was that the inter-departmental communications, prior to the performance of the surveillances, were not effective. This was based on the lack of documented surveys and log entries regarding the surveillances in both the Operations and RP logs. In addition, unlike other plant procedures which require inter-departmental coordination, the HPCI and RCIC surveillance procedures do not specifically require RP Department notification for the assessment of changing radiation fields. The inspector concluded that the lack of a radiation survey during turbine operation represented a missed opportunity and poor work practice with respect to ALAPA (As Low As Reasonably Achievable) considerations. Actual radiological conditions did not change in this instance. The RP Manager acknowledged the inspector's conclusions and planned to _ emphasize this concern with RP personnel. 4.0 MAINTENANCE AND SURVEILLANCE (62703,61726) 4.1 Maintenance The inspectors observed selected maintenance on safety-related equipment to determine whether these activities were effectively conducted in accordance with VY TS, and administrative controls (Procedure AP-0021) using approved procedures, safe tagout practices and appropriate industry codes and standards. 4.1.1 Failure of Service Water Valve Anti-Rotation Key On June 15, the inspector observed control room operator response to a stuck open residual heat removal service water (RHRSW) valve 89A being used during containment cooling. The valve failed at 35 percent open and did not respond to operator control. The valve is used to throttle service water flow from the RHR heat exchanger. The operators promptly declared the containment cooling subsystem inoperable, entered the applicable TS action - statement, and notified the Maintenance Department. Maintenance Department personnel commenced troubleshooting and repair in accordance with emergency work order no. 93-4041 and identified that the motor pinion gear key, located in the motor operator portion of the valve, was missing. This key splines the drive motor shaft to the motor pinion gear to prevent rotation. In addition, a set screw (which pins the motor shaft to the pinion gear preventing axial motion) was found to be excessively worn and unable to perform its function. Both retaining devices were replaced, the motor shaft and gear inspected, post-maintenance testing conducted, and the valve returned to service that day. The key was found in the motor grease and was observed to have rounded edges (an indication of excessive wear). Vermont Yankee attributed the root cause of the failure to cyclic stress induced on the key by the motor cycling and by system vibration. __ - '

__ _ _ _ _ _ _ _ _ _ _ - _ _ . . 6 On June 18, the inspector discussed the key failure with the Maintenance Manager and cognizant engineers and concluded that VY's efforts to correct the failure were timely. However, limited documentation existed regarding the "as found" condition of the key, key way, set screw, motor shaft and gear. The inspector considered the measurement and documentation of these critical attributes important to a comprehensive determination of root cause. These attributes would also enable an assessment of common cause failure on similarly configured motor operators should failures occur in the future. Vermont Yankee concluded that no immediate corrective action was necessary to improve the installed key configuration based on the lack of similar past failures and because such a key failure was dependent on time in service (valve 89A had approximately twice the service life of 89B). The licensee inspects each of these valves once every three years on a rotating basis, and intends to inspect RHRSW-89B during the week of July 12. Modifications to both RHRSW subsystems will be implemented during Refueling Outage XVII (August 1993) to, in part, reduce system vibration and cyclic stress on the motor key. Notwithstanding inspector's concern for root causal analysis, the licensee's actions were concluded to be appropriate and the replacement of these valves in the upcoming outage will be followed in future NRC inspections (IFI 93-13-02). 4.1.2 Standby Gas Treatment - LCO Maintenance During this inspection period, VY voluntarily entered the TS limiting condition for opei Ttion (LCO) action statements for the "A" and "B" standby gas treatment (SBGT) systems to perform maintenance and surveillance. The inspectors conducted direct field inspection to assess this LCO maintenance. Interviews were conducted with the cognizant engineer, mechanics, and Instrument & Control Department technicians. Internal VY commitment items, the Final Safety Analysis Report, TSs, and Regulation Guide 1.52, " Design, Testing, and Maintenance Criteria for Post-Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants," were reviewed. In addition, applicable plant procedures and the SBGT pre-operational testing, performed prior to initial reactor startup, were also reviewed to support this inspection. Each SBGT train was sequentially taken out of service for approximately two days of the 7- day LCO period. The surveillances verified the efficiency of the HEPA and charcoal filtering elements, calibrated system instruments, and identified a wiring discrepancy associated with the "B" SBGT system airstream thermocouple. The maintenance focused on the field verification and correction of system configuration discrepancies associated with sealing gaskets, bolts, and charcoal tray thermocouples. In addition, preventive maintenance and inspections were performed on the SBGT fan, moisture separator, and sight level gage. Management controls and the disposition of identified deficiencies were good. For example, following maintenance on the "B" SBGT system in November 1992, VY identified and evaluated several minor problems with the "as-found" configuration of the carbon tray ,

_ _ . . . , 7 l , thermocouple (TE-1-124-4B) and the location of the tray itself. Corrective actions were implemented to assure that these configuration control issues were properly corrected during current maintenance. A second example involved the identification of concerns regarding the ' qualification of gasket materials. Vermont Yankee was concerned that the installed gaskets would not maintain seal integrity during post-accident radiation exposure. Vermont Yankee management delayed entry into this current maintenance to complete an engineering I evaluation of the as-found configurations; the licensee concluded that no system operability concerns existed. The inspectors reviewed these assessments and found them to be ! appropriate. Pre-planning effectively supported the maintenance and surveillance performed. The work . package was comprehensive based on the incorporation of technical literature, one-for-one , evaluations, and inter-department memorandums that described the gasket and thermocouple

issues. The cognizant engineer demonstrated detailed knowledge of the issues and provided effective oversight of the maintenance performed. Maintenance and I&C Department personnel were experienced and followed work instructions. A problem involving the segregation of safety and non-safety related bolting was identified by the inspector, but l ! promptly corrected by VY. Overall, the LCO maintenance was well managed, and , consistent with NRC guidance for this work.

4.1.3 Circuit Breaker Maintenance ' During this period, maintenance was performed on the 4KV AC breaker for the "A" service 3 water pump (P7-1-A). The inspector performed a field inspection of this activity, . interviewed the electrician, and reviewed the work package. Plant procedure OP 5222, Rev. { 11, "4KV AC Circuit Breaker Inspection, Calibration and Testing," NRC Information Notice ! 90-41, " Potential Failures of GE Magne-blast Circuit Breakers and AK Circuit Breakers," and General Electric (GE) Service Advice Letter 073/348.1, dated December 7,1990, were reviewed by the inspector. The inspector concluded that the work package and documentation of identified deficiencies were comprehensive. The work package contained the GE service information and the one- for-one evaluation regarding this industry information, the applicable circuit breaker technical manual, and appropriate work release documents. Manufacturer-recommended lubricants were in use and correctly illustrated in OP 5222. The field notes were documented directly on the breaker inspection report, and clearly described identified deficiencies. Attention to detail was demonstrated by the electrician in the identification of an out-of-position trip spring and commutator wear indications. Engineering evaluation of the deficiencies was also timely. , -. _ _ __

.. . 8 i 4.2 Surveillance The inspector reviewed procedures, witnessed testing in-progress, and reviewed completed ] surveillance record packages. The surveillances which follow were reviewed and were found effective with respect to meeting the safety objectives of the surveillance program. The i inspector observed that all tests were performed by qualified and knowledgeable personnel, i and in accordance with VY Technical Specifications, and administrative controls (Procedure AP-4000), using TS approved procedures. OP 4111, Rev. 24, " Control Rod Drive System Surveillance"

OP 4115, Rev. 29, " Primary Containment Surveillance"

, OP 4116, Rev.14, " Secondary Containment Surveillance"

OP 4117, Rev.17, " Standby Gas Treatment System Surveillance"

- OP 4120, Rev. 26, "High Pressure Coolant Injection System Surveillance"

,

OP 4121, Rev. 24, " Reactor Core isolation Cooling System Surveillance"

OP 4160, Rev. 23, " Turbine Generator Surveillance" OP 4424, Rev.17, " Control Rod Scram Testing and Data Reduction"

OP 4501, Rev. 7, "Fiker Testing" 4.3 (Open) VIO 93-13-02: Core Spray Sparger Break Detection - Nonconservative Setpoints i 1 On May 25 an auxiliary operator (AO) conducting routine rounds in the reactor building identified that core spray differential pressure instrument DPIS-14-43A was indicating below zero pressure. Instrument DPIS-14-43B, which is mounted directly below the "A" instrument, was indicating at (but not below) zero pressure. The AO assessed that the condition potentially reflected anomalous equipment performance and reported it to the Shift

Supervisor (SS). A work order to address the downscale indication on DPIS-14-43A was initiated and I&C Department personnel were assigned to investigate. At 8:50 a.m., May 25, the SS declared the "A" core spray subsystem inoperable and entered the action statement for TS 3.5.A.2 which allows seven days of continued plant operations. 1 Plant Procedure OP 4347, Rev.14, " Core Spray Header Differential Prcssure Functional / Calibration," was used to facilitate the investigation. Initial corrective actions identified the need to repair the internals of the instrument. However, the instrument's ! maintenance history file and procedure OP 4347 stated that a 0.75 pounds per square inch differential (psid) head correction needed to be applied to "zero" the instrument, but the technical investigation determined that a 1.9 psid value was necessary for full power ) i conditions. l

. .. 9 Background Each core spray (CS) subsystem has a detection system to confirm the integrity of the piping between the inside of the reactor vessel and the core shroud. A differential pressure indicating switch (DPIS) measures the pressure difference between the bottom of the core and the inside of the CS sparger pipe just outside the reactor vessel (high and low pressure sides, respectively). With the instrumentation connected across the core shroud in this fashion, it i provides a negative pressure indication during normal operation but a positive pressure if a core spray line break were to occur at power. The setpoint value used to calibrate the instrument to read 0 psid at full power is designated as the " head correction." The switches

used at VY are Barton Model No. 288, designated as DPIS-14-43 A/B, do not have a negative valued scale (i.e., they cannot indicate negative pressures). An increase in the normal pressure drop at power (from a negative to a positive differential) initiates an alarm in the control room. The corresponding alarm response procedure requires operator actions to verify that the differential pressure is legitimately high, and to consult the applicable TSs. Regarding the alarm setpoint and instrument operability requirements, TS Table 3.2.1 specifies that the alarm trip level setting shall be less than or equal to 5 psid; if , the alarm channel is not available (or operable), then the respective CS subsystem is to be

considered inoperable and the requirements of TS 3.5 apply. Detailed Investigation The established head correction for the DPIS-14-43B instrument was 1.9 psid and, because

the monitoring systems for both CS subsystems have identical instrument piping arrangements, it was unclear as to why the "A" side would have a different value (0.75 psid) for the established head correction. Further investigation by both I&C Department and , Engineering Department personnel determined that both correction values should be the ! same. ! In September 1979, the General Electric Co. (GE) issued Service Information Letter (SIL) l No. 300 that addressed a situation where the subject DPIS instruments were routinely indicating downscale during plant operation, an operational nuisance and potentially bad i practice. The SIL also provided information for BWR operators to review the calibration of this instrumentation. For VY, a maximum expected change in differential pressure across

the core shroud following a sparger break was calculated by GE to be 4 psid; however, a question as to appropriateness of the TS stated 5 psid instrument alarm setpoint value was not l recognized during the 1979 review of the SIL. The VY investigation identified inadequacies in procedure OP 4347 involving an incorrect and inconsistent methodology in applying the head correction factor. Specifically, a 4.0 f. 0.3 psid alarm trip value, as indicated on measuring and test equipment, was used to set the instrument's alarm switch; however, the actual head correction sensed by the system (i.e., the -1.9 psid measured value across each instrument) was not considered in arriving at the ,

. i . 10 ! instrument alarm setpoint. This resulted in the actual alarm switch being set at approximately 5.9 psid and, therefore, nonconservative with respect to the TS. The actual ' " zeroing" of the indicator pointer to preclude downscale indication has no actual affect on the alarm setpoint due to the nature of the switches' internal mechanism. 1 Corrective Actions t At 8:30 p.m. on May 27, following VY's identification that the OP 4347 calibration , ' procedure incorrectly set the alarm points nonconservatively with respect to the TS value, both the "A" and "B" CS subsystems were declared inoperable in accordance with TS Table . 3.2.1. The procedure was revised to correct the nonconservative conditions and DPIS 14- 43B was recalibrated and returned to operable status three hours later. The DPIS 14-43A instrument was made operable on May 28 at 1:25 p.m. Vermont Yankee held discussions i with General Electric Co. technical representatives to ensure that their corrective actions , were consistent with the plant's design. Regarding past missed opportunities for VY to have identified the setpoint deficiencies, the inspector noted the applicability of two relevant activities: (1) the disposition of NRC Information Notice 91-75; and (2) the biennial procedure review process. NRC Information Notice 91-75, " Static Head Corrections Mistakenly Not Included in Pressure Transmitter Calibration Procedure," was intended to alert licensees to situations where errors were found in the calibration of pressure transmitters that occurred because the effects of static pressure had not been considered, or had been considered inappropriately. Vermont Yankee's action l to address the " lessons-learned" from this document was to create a procedure comment file to have the I&C Department add references to head corrections in the discussion section of all applicable calibration procedures during the next biennial review for the subject procedures. When Revision 14 of procedure OP 4347 was issued on December 7,1992 (its i next biennial revision), the head corrections of 0.75 and 1.9 psid for the respective switches were added from the equipment history file. There were no evaluations performed to ensure the accuracy of the existing setpoints. 1 The biennial review process at VY is intended, according to procedure AP 0037, " Plant ' Procedures," to be a comprehensive review of the entire procedure. Specifically, the cognizant department head has the responsibility to ensure that the procedure is reviewed for technical adequacy, including compliance with the TSs. Vermont Yankee's actions to strengthen the biennial review process had become the cornerstone of their corrective action to address a number of past missed smveillances that were related to poor or inadequate procedures. Safety Significance and Conclusions The switches were nonconservatively set, above 5.0 psig, since 1979. However, the switches only feed an alarm and do not result in a loss of function of the core spray system. The lack of an alarm which would annunciate upon a sparger piping break inside of the _ -

4 l - , 11 reactor vessel does not affect the ability of an engineered safeguards feature to mitigate accident consequences; rather, what was lost was the ability to detect a relatively low ] likelihood passive piping failure. Other programs such as inservice inspection (ISI) exist to

detect and prevent such failure mechanisms as intergranular stress corrosion cracking. Nonetheless, both channels were inoperabic for a period in excess of ten years, and several opportunities were missed to identify and correct this condition. A good questioning attitude was demonstrated by the equipment operator in identifying anomalous instrumentation performance. Previous biennial procedure reviews and industry experience evaluations which missed this problem, however, indicate weaknesses in those processes. Vermont Yankee failed, as far back as 1979, to provide proper technical guidance in the form of a surveillance procedure to ensure the correct implementation of a TS required setpoint for the core spray sparger high pressure alarm. This failure to ensure that TS Table 3.2.1 requirements for this alarm function were met was determined to be a violation of NRC requirements (VIO 93-13-03). 5.0 SECURITY (71707, 92700, 93702)

The inspector verified that security conditions met regulatory requirements and the VY Physical Security Plan. Physical security was inspected during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. During this period, the inspector walked down portions of the Protected Area fence and observed that security personnel properly responded to perimeter alarms. During a night ' tour, the inspector found the security lighting acceptable. On June 25, the inspector . observed security personnel appropriately search and escort a vehicle onsite, inside the protected area. 6.0 ENGINEERING AND TECIINICAL SUPPORT (71707,62703) 6.1 Appendix J Testing: Drywell IIydrogen/ Oxygen Monitoring System On February 5, VY identified that portions of both drywell hydrogen / oxygen (H2/02) monitoring systems were not leak rate tested in accordance 10 CFR Part 50 Appendix J, , ! " Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Both systems were declared inoperable, leak rate tested, and restored to service. The H2/02 system provides continuous sampling of oxygen and hydrogen concentrations within containment, and provides alarm and indication in the control room. Potential Reportable ] Occurrence Report No. 93-09 and Licensee Event Report (LER) 93-03 documented VY's engineering evaluation and corrective actions implemented for this issue. I Vermont Yankee identified this discrepancy following preventive maintenance of the H2/02 monitoring systems in January 1993 (NRC Inspection Repon 93-02). During this maintenance, system components that form part of the primary containment pressure boundary were removed and reinstalled. local leak rate testing (LLRT) was part of the post- ,

. _ _ __ _ , - 4 i . 12 maintenance testing and performed in accordance with procedure OP 4029, Rev 6, " Type A - ) Primary Containment Integrated Leak Rate Testing." However, the procedure was ) inadequate in that tubing downstream of a safety class check valve was not vented to atmosphere, and tubing within both monitor cabinets was not subject to test pressure. The inspector reviewed procedure OP 4029, the root cause determination, and LER 93-03 and concluded that VY's assessment of this issue was adequate. The inspector concurred with the licensee's root cause determination in that VY failed to adequately perform leak rate testing due to an inadequate procedure. However, the inspector also considered the biennial l review of the procedure ineffective because the testing inadequacy was not previously identified. The immediate and proposed long-term corrective actions were appropriate. The results of the LLRT performed in response to the identified discrepancy were satisfactory and identified no system integrity concerns. Similarly, the overall integrated leakage rate was re-calculated using the new LLRT value and found within acceptable limits. The proposed independent assessment and rewrite of the Appendix J testing program was appropriate and intended to improve the overall quality of the program and prevent recurrence of similar deficiencies. This effort is scheduled for completion by the third quarter of 1994, prior to the next

scheduled Appendix J test in Refueling Outage XVIII. This violation involving the failure to , properly leak rate test the H2/02 monitors meets the criteria for enforcement discretion in Section VII of the NRC's Enforcement Policy, and will therefore not be cited. ' r ! 6.2 Water Ixvel Instrumentation Errors During and After Depressurization , Transients (TI 2515/119) ' The inspector verified that VY implemented operator training and guidance regarding reactor water level instrumentation errors during and after rapid depressurization events and that this material was consistent with current plant Emergency Operating Procedures (EOPs). As part i of this assessment, the inspector interviewed the VY training staff and a number of control - room operators (CROs), and reviewed training matenals. Previous review of this issue and recent water level instrumentation anomalous performance at VY are documented in NRC Inspection Reports 92-21 and 93-08. Two simulator scenarios were observed to verify that CROs were trained to respond to the failure of reactor vessel water level instrumentation caused by a rapid depressurization transient (Section 2.4). The EOPs appropriately led operators into reactor vessel flooding and depressurization actions and provided clear information when such activities were required. Even though the EOPs do not clearly define all situations involving "when reactor water level is undetermined," the operators interviewed demonstrated adequate knowledge of - explicit plant indications which necessitate this EOP entry condition. Simulation of undetermined reactor water level is based on reference leg flashing due to saturation conditions; the computer algorithm does not simulate level anomalies due to degassing of { noncondensables. , E

. _ . 13 The safety parameter display system (SPDS) models reactor vessel water level failures and level indication identical to that available in the control room. In addition, SPDS color will change when data exceeds acceptable tolerances. This modeling assesses the validity of discrete level values and the statistical variations between channels to determine the acceptability of processed information. Because level divergence between channels is not specifically assessed nor displayed by the computer algorithm, CROs perform log keeping to document level divergence. The inspector reviewed the VY training lesson plans for reactor water level instrumentation and determined that the plan adequately describes the effects of noncondensable gases in reference legs. The training references Generic Letter 92-04 and VY's response, and ~ incorporates discussion regarding water level anomalies experienced at another boiling water reactor (BWR) facility. Further, Operation's Department Night Orders were issued to enhance CRO knowledge of level anomalies that have occurred in the industry. Based on a sampling of CROs interviewed, operators indicated an adequate level of knowledge in regards to industry issues; however, operators had some difficulty in articulating the differences between the level anomalies observed at VY in April 1993 (NRC Inspection Report 93-08) and recent industry experiences. Industry information has also been incorporated into the training program, however, the 8-step level determination test (BWROG-92096, dated October 16,1992) will uot be implemented. Augmented training, as required by NRC Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," will be completed on August 13,1993 (VY letter dated June 9,1993 to the NRC). 7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (90712,90713, 92700) 7.1 Periodic and Special Reports The plant submitted the following periodic and special reports which were reviewed for accuracy and found to be adequate: Monthly Statistical Report for May 1993

Monthly Status of Feedwater Nozzle Temperature Monitoring

Report of Fuel Failure Status and Parameter Trends for May and June 1993

7.2 Licensee Event Reports The inspector reviewed the following Licensee Event Reports (LERs) and concluded that: (1) the reports were submitted in a timely manner, (2) the description of the event was accurate, (3) a root cause analysis was performed, (4) safety implications were considered, and (5) corrective actions implemented or planned were sufficient to preclude recurrence. ______ _ _ -

__ . J . 14 93-01, Supplement 1: " Degraded Vital Fire Barriers Due to inadequate

Documentation of Assumptions and Inadequate Procedures." NRC evaluation of degraded fire barriers is documented in NRC Inspection Report 93-05.

93-03: " Failure to Properly Leakage Rate Test Portions of the Primary Containment Hydrogen / Oxygen Monitoring System" (refer to Section 6.1).

93-06: " Core Spray Systems A&B Declared Inoperable Due to Calibration Procedure Error" (refer to Section 4.3). 8.0 MANAGEMENT MEETINGS (30702) l 8.1 Preliminary Inspection Findings Meetings were periodically held with plant management during this inspection to discuss inspection findings. A summary of preliminary findings was also discussed at the conclusion of the inspection in an exit meeting held on June 30. No proprietary information was identified as being included in the report. 8.2 Enforcement Conference l On June 15, an enforcement conference was held at the NRC Region I office with VY representatives to discuss control rod performance involving inadequate scram insertion times. A list of meeting attendees and copies of overhead slides used in the VY presentatian are contained in Attachments A and B to this report. l

- . _ _ _ _ . . ATTACHMENT A LIST OF ATTENDEES , ENFORCEMENT CONFERENCE JUNE 15,1993 NRC Attendees E. Imbro, Acting Deputy Director, Division of Reactor Safety (DRS) C. Hehl, Division Director, Division of Reactor Projects (DRP) ' P. Eapen, Chief, Systems Section, DRS W. Butler, Project Director, Project Directorate I-3, Office of Nuclear Reactor Regulation (NRR) L. Prividy, Team leader, DRS M. Banerjee, Sr. Enforcement Specialist, Office of Regional Administrator T. Shedlosky, Project Engineer, DRP , E. Kelly, Chief, Reactor Projects Section 3A, PB3, DRP i H. Eichenholz, Sr. Resident Inspector J R. Matakas, Investigator, Office of Investigation B. Whitacre, Reactor Engineer, DRP R. DePriest, Reactor Engineer, DRS J. Petrosino, Vendor Inspection Branch, NRR P. Drysdale, Sr. Reactor Engineer, DRS Licensee Attendees ) D. Reid, Vice President, Operations R. Wanczyk, Plant Manager J. Herron, Technical Services Superintendent { M. Watson, Manager, Instrumentation and Controls M. Benoit, Manager, Reactor and Computer Engineering P. Corbett, Sr. Electrical Engineer, Engineering P. Bergeron, Manager, Transient Analysis, Yankee Atomic Electric Company i < i

. _ _ _ _ . - ___ _ O ' . ATTACHMENT B SLIDES FROM JUNE 15,1993 , ENFORCEMENT CONFERENCE , E ! ! l

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,- _ . . . , ,e . 1 - ATTACHMENT B ' .. . . _ JUNE 15,1993 ENFORCEMENT CONFERENCE CONTROL ROD DRIVE INSERTION TIMES I. INTRODUCTIONS II. REVIEW OF OCTOBER,1992 SCRAM TIMING SURVEILLANCE / TECH SPEC REVIEW III. ASSESSMENT OF OCTOBER,1992 RESULTS AND CORRECTIVE ACTIONS IV. DESIGN CONTROL PROGRAM V. SHELF LIFE CONTROL PROGRAM VI. SCRAM TIMING SURVEILLANCE TASK FORCE EFFORTS AND CORRECTIVE ACTIONS VII. SAFETY SIGNIFICANCE VIII. SUMMARY < 1

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. .. 1 9 , . f I REVIEW OF OCTOBER,1992 SCRAM TIMING l SURVEILLANCE AND TECH SPEC REVIEW . o SINGLE ROD SCRAM TIME TESTING / RETESTS o EVALUATION , o MANAGEMENT REVIEW - ENGINEERING INPUT - STANDARD TECH SPECS - TECH SPEC INTERPRETATION - REVIEW OF PRIOR TRENDS ) o PRO DOCUMENTATION j , -a

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. _ BASES C. Scram Insertion Times The Control Rod System is designed to bring the reactor subcritical at a rate fast enough to prevent fuel damage. The limiting power transient is that resulting from a turbine stop valve closure with a failure of the Turbine Bypass System. Analysis of this transient shows that the negative reactivity rates resulting from the scram with the average response of all the drives as given in the above specification, provide the required protection, and MCPR remains greater than the fuel cladding integrity limit. , '

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l . ~ 3.3 L1 HIT 1HC CONDITIONS FOR OPERATION 4.3 SURVEILLANCE REQUIRDfENTS -

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' C. Scram insertion Times _ C. Screes Insertien Times . 1. Af te'r refuelitig outage and" priot to* operation , 1.1 The average scram time, based on the ' de-energitation of the scram pilot above 30% power with reactor pressure abovu , valve notenoids of all operable control 800 peig all control rode shall be dubject to

rode l'n the reactor power operation scram 41me measurements f rom the fully . condition shall be ho greater thant withdrawn position. The scram times for single tod scram testing shall be measured without - Drop-Out of 11neerted From Avg. Scram Insertion , reliance on the control rod drive pumpe. Position Fully Withdrawn Time (sec) 2. During or following a controlled shutdown of the . 0. 358 ' reactor, but not more frequently than 16 weeks 46 4.51 . 36 25.34 0.912 nor less frequently than 32 weeks intervate, 26 46.18 1.468 50% control red drives in each quadrant of . 06 87.84 2.686 the reactor core shall be measured for scram ! times specified in Specification 3.3.C. All

The average of the scram insertiorl times control rod drives shall have esperienced for the three fastest control rods of all scram-time measuremente each year. Whenever 50% of .the control rod drives scram times have e , groups of four control rods in a two by . two stray shall be no greater than: been measured, an evalus' tion shall be made to provide reasonable assurance that proper

- Drop-Out of IInserted From Avg. Scram Insertion control rod drives performance is being position _ Fully Withdrawn Time (sec) maintained. The results of measuremente per- formed on the control rod drives shall be , , 46- 4.51 0.379 submitted in the start up test report. '

36 * 25.34 0.967 26- 46.18 1.556 . 06 87.84 2.848 . , , t .w, . , , , , - ' i . , , , , VYH1'S - ! . . .

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. .. 3.3 L1 HIT 1HG CONDITIONS FUR OFERATION 4.3 SURVEILIANCE REQUIREMENTS

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' I,3. If Specification 3.3.C.1.2'cannot he met, 9..:. the reactor shall not be made super- ' . t

criticalg if operating, the reactor ,

ehall be shut down leanediately upon determinetton that average scene time , ' is deficient.

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1 -j . 111 ASSESSMENT- OF OCTOBER,1992 RESULTS AND 1 CORRECTIVE ~ ACTIONS-

i 1 A) PRO 92-083 Evaluation j ! B) Trend Evaluation

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C) Trending Methods i

D) Scram Time Testing Methods j i a E) Scram Testing Procedure Requirements ! ! F) Scram Time Projection ! G) Sensitivity Study , i l i ! '! ! !

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. ._ ,. . . VermontYankee

~ fttch 46 Scram Time - All Ehta , 0.4 0.38 + 0.36 - 4+ m + 4+ + + + i 0.34 +- +-+-+ + - - + o + + + + + + 8 0.32 +-++-

+ + ai 0.3 +- + 4+- E ++ <<+ + + + + + + .F- 0.28 +-+ -+ <<+-+ - 4+ + + $ + + + + + + '+ + 4+ 0.26 + + + 0a + + + + 0.24 + + + 0.22 0.2 80 90 100 110 120 130 140 150 160 Scram ihmber - - - - - - - . - . . . . . .. ... . - . - . . . . . . -

. _. . . .. . .. VermontYankee - - - ' tbtch 46 Scram Time - Automatic Scrams O.4 0.38 0.36 f 0.34 O g 0.32 + e + ar 0.3 + + <+ E ++ <<+ + + + + + + F 0.28 +-+ -+ < < + - + - 4+ + + e + + + + + + '+ + (+ 8 0.26 + + -+ o + + + + . 0.24 + + + 0.22 0.2 , 80 90 100 110 120 130 140 150 160 Scram Number . . . . . - .. .- -

- . - . . . O m ' Vermont Yankee . tbtch 46 Scram Time -Pbwer Testing 0.4 0.38 + 0.36 <+ m + + ' j 0.M +-+ + o + g 0.32 + . i - a + ar 0.3 E F 0.28 m 8 0.26 i O 0.24 0.22 0.2 < 80 90 100 110 120 130 140 150 160 Scram MJmber - - - - - - . . - . .. . . - - - -

' . . ~ - .. . . . 0 . 6 - 1 + + . 0 - 5 1 + . 0 g + 4 1 n it . se - T . - c + 0 . ita 3 t 1 e s + . e o r . r e d + b kny aH m - - Y 0 b . - t 2 P ne + 1 - om m mT a i r r c _ e m S V a _ r 0 . c 1 S 1 6 + . - 4 - h . c t + . t 0 f 0 1 - - + 09 + + 0 - 8 4 8 6 4 2 3 8 6 4 2 2 0 3 3 3 3 0 2 2 2 2 0 - 0 0 0 0 0 0 0 0 . r mt5gwaEFo3O t .

, .. ,. . . . - 3REJ::CTIOsl FOR APR::_ 6,

.993

SING _E RO] SCRAv TEST:: NG i 7 CYCLE 16 HYDRO DO 46 AVG. 0.344 SECONDS . ' BOC BOC O.348 0.340 DELTA = 0.008 DELTA = 0.016 Y b OCT 92 APR 93 AS-LEFT = 0.356 PREDICTION = 0.356 AS-FOUND = 0.366 ACTUAL = 0.384 ..

- . . . . . . , , . , VY DESIGN CONTROL PROCESSES Process Senp_e ' Maintenance Request Plant or Security Equip. = = PM or CM No changes to essential criteria = Non identical components with One ' = for One or Equivalency Evaluation Work Request Non-Plant / Non-Security = Temporary Modification = Renders Plant equipment unlike I current design Temporary in Nature = Eng. Design Change Change in Plant Design = YNSD initiated = Plant Design Change Change in Plant Design = = Plant initiated One for One Evaluation = Non identical part or comp. Equal or better = Compare critical characteristics = Equivalency Evaluation Alternate Replacement Items = During Procurement Process = Compare critical characteristics =

_ ", '. . . . .. . COMPONENT REPLACEMENT PROCESSES Process Preparation Approval , One for One Eval. Engineer Eng. Supervisor (AP 0008) , Equivalency Eval. Procurement Eng. Supervisor (VYP:329) Engineer

Future- Combination of two processes for consistency

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., . . . . SCRAM SOLENOID O-RING REPLACEMENT = 9/91 I&C initiated efforts to replace O-rings .with Viton 1 = 9/91 Verbal contact to YNSD I&C Eng., approval & EQ doc. = 9/9/91 Requisition for Viton 0-Rings initiated 9/10/91 Procurement Eng. review of requisition = assessed critical characteristics = 9/11/91 One for One Evaluation by Engineering Emphasis was EQ/ aging aspects

Ref. YNSD eval. & documentation 9/11/91 EQ Documentation Issuance = 9/13/91 0-Rings changed to viton in two leaking 117 = valves , = 4/92 1992 Refueling Outage, Installed Viton 0-rings in 117 valves = 4/93 1993 SCRAM Timing Event, Refurbished 117 & 118 valves, Buna-N 0-Rings used ) ___ _ _ _ - _ _ _ _ - - _ _ - _ _ _ _ _ _ _ _ _ _ _ _

_ -_ i = . . . . ., . .. J SCRAM SOLENOID O-RING REPLACEMENT Conclusions Significant review and approval = I&C Engineering - I&C Supervisor - YNSD I&C Engineering - Procurement Engineering - Plant Engineering - Plant Engineering Supenrisor i - Dimensions identical, key attribute EQ/ aging. Viton = superior properties to Buna-N and concluded to be an acceptable replacement = Since performance of other valve elastomers was monitored by factors other than SCRAM air header leakage, air leakage was not considered as an indication of degradation No consideration given to coordinating with ASCO or GE = as Environmental Qualification was not based on ASCO/GE Reports but on a VY specific DOR Qual. Report. Key attribute affecting SCRAM Timing was not being changed Euture Actions Review for enhancements from lessons learned (broader = implications of premature components failures and consideration for vendor contacts)

- . ,. . . .. , SERVICE LIFE OF SCRAM l SOLENOID PILOT VALVES (SSPVs) i References: = GE SIL 128 GE Letter, HPW87.018 to S. Moriarty (VY), = dated June 6,1987 VY Procedure DP 0313, " Equipment Service = Life Tracking" VY I/C EQ File 3-6 =

.. _ . . . ,. .. . .. . Service Life is 7 years maximum (with no = ' shelf life correction; any shelf life must be deducted from service life). l 90% degradation is considered end of life, = thus a service life of 6.3 years (again with no 4 shelf life correction applied) maximum is applied on the SSPVs. ]

A 5% service life degradation occurs with 6 = year shelf life, a 10% service life degradation occurs with a 12 year shelf life. EQ File 3-6 states: "I/C engineering = concurrence is required if valve kits or pilot . head kits have an assemble date greater than

two years from the installation date." Thus, - without I/C engineering involvement a two- 1 year span from assembly date to installation date is possible (worst case). i

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E A

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' l l DESCRIPTION OF EVENT - 4/6/93

Performed single Rod Scram Testing IAW = Technical Specifications 4.3.C.2 during scheduled R.P.E. = Results were as follows: l o Core Wide average notch 46 = .359 o Seven (7) 2 x 2 arrays ranging from .380 to .418 Task team developed to determine the cause of = ' the slow scram times to notch 46 1 l ! l- . .- - . - - -

- - - - - .- ~ .. .. .. . . e 1 TASK TEAM , p 7 O

A multi-disciplinary task force was formed of plant individuals from:

1. Reactor and Computer Engineering f 2. I&C 3. Mechanical Maintenance ) 4. Operations j . The General Electric -Company lead system engineer for the Control Rod Drive (CRD) system and a design engineer from Automatic Switch Company (ASCO) were added to the team. MISSION Investigate the slow, changing and inconsistent ' scram times, determine the root cause and recommend any necessary repairs. i

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. . . ! a TASK TEAM i

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A sub-task team was added that was headed up by Vermont Yankee's Engineering Director. This team was formed of- plant i engineering experts in the EQ, materials and q procurement areas. MISSION To acquire physical data from scram solenoid pilot valves (SSPV's) to identify a root cause within the values. i _ . - - ..

, - . . .. . . , . TASK TEAM

D An independent fact-finding team was assembled from the Yankee Nuclear Services Division. The team consisted of the following: 1. Technical Director, Yankee Nuclear Rowe Station (Rowe) 2. Engineer, Vermont Yankee Project 3. Director, Nuclear Engineering Department 4. Lead Engineer, Reactor Physics Group Two of the members of this team are members of our Nuclear Safety Audit and Review Committee (NSARC). MISSION Charged with evaluating scram time testing methods used at Vermont Yankee in addressing Technical Specifications Review Technical Specification scram time testing requirements = Evaluate past data gathering and use in determination of control = rod scram insertion time, including the use of "As-Found" and "As-Left" data I Review of industry practice with respect to scram time testing = An evaluation of the use of scram time data to show compliance = with VY Tech Specs An examination of plant management expectations with respect to = the use of scram time data Recommendations to improve scram time testing practices in the = future . 1 1 -

. . .. ' .- . _ SIGNIFICANT CORRECTIVE ACTION REPORT TASK TEAM #1 - ROOT CAUSE = Root Cause o The refurbishment kits installed in the SSPVs during the 1989 refueling outage (#14) have component (s) that have an unknown reduced capability compared to the present ones installed and components that have deteriorated over time. The combination of the two deficiencies have led to the slow Start of Motion times. Contributing Root Cause(s) = o The contributing root causes deal with a number of programmatic issues that contributed to the lack of attention paid to deteriorating scram times

._ _ _ . - . .- ... , . . . . TASK TEAM SUMMARY ON SSPV CEP techniques used for the determination of slow scram =

times l

The Scram Solenoid Pilot Valves were the cause of the- = ! slow scram times - The Start of Motion (SOM) was the specific definition of i = the area of concern !

All 89 Control Rod Drive SSPV's were replaced - total of = 178 kits 1 April 14,1993 - Cold Hydro Test results I =

o Core wide average time to notch 46 = .320 see o No 2 x 2 array issues April'17,1993 " HOT" At Power Test results =

! o Core wide average time to notch 46 = .312 sec l o No 2 x 2 array issues

I Both Hot and Cold Test data are Vermont Yankee's best = times , June 6,1993 " HOT" At Power additional testing results. =

1 o Core wide average time to notch 46 = .316 ! o No 2 x 2 array issues i a $

', . .,. . .. . . . SIGNIFICANT CORRECTIVE ACTION l REPORT RECOMMENDATIONS l TASK TEAM #1 ! Summary of Recommendations

= Refurbish all SSPV's GE and ASCO to perform material testing = ! = Establish Administrative Limits l t

Evaluate CRD HCU preventive maintenance j = i Improve procedural controls = Evaluate Tech Spec Section 3.3.C/4.3.C = = Issue Part 21 Evaluation Evaluate the Single Rod Scram Test Panel = Engineering evaluation of RPS voltage = Evaluate Scram Air Header Pressure = Self-assessment of other Tech Spec areas = Re-Evaluate SIL-128 = Determine the need for additional QA audits GE/ASCO = Determine assumptions used for 7-year service life = YAEC to evaluate past audits of GE/ASCO = = Reconvene task team to assess CA effectiveness

- - - - - - - - - - - - _ - '. . . .. .. . SUMMARY OF PROGRAMMATIC ISSUES TASK TEAM #3 Final Report Summary Technical Specification Review = Review of Test Records = Review of As-Found Data Records = Evaluation of Corrected Full Scram Data = Review of Technical Specification Compliance = Review of Industry Practice a . Management Expectations =

. .. . .. . . d TECHNICAL SPECIFICATION REVIEW ' . Apparent contradiction within Tech Spec Section 4.3.C.1 = vs 3.3.C.3 Tech Specs do not differentiate between As-Found and = As-Left Must use As-Found to meet the requirements of the = surveillances section of Tech Specs Re-testing should be allowed only for the following = reasons: i o Test recorder failure o Data not retrieved or illegible o Part of a maintenance /PMT activity o Following a refueling / maintenance outage for the purpose of insuring operability Separate the procedures for specific Tech Spec section = implementation " Average Scram Time" does not differentiate between = core wide average and 2 x 2 array Tech Spec 3.3.C.3 requires an immediate shutdmvn if = section 3.3.C.I.2 (scram times) is not met ,

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SCRAM TIME DATA GATHERING AND DATA ANALYSIS

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30 pen full scram recorders have ~ a 30 = millisecond non-conservative error No recorder error on single rod scram testing =

I Review of the BADTIME program was found = to be in full compliance with Tech Specs '

Conservative errors were verified with the = . Single Rod Scram Test Panel (up to .070 sec) . 1 s . -.s . - - --

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I REVIEW OF TEST RECORDS l i . l Long standing practice to perform re-testing = - No distinction between Cold Hydro testing and = At Power Single Rod Surveillance Testmg ! Re-testing was conducted for slow scram times = along with poor test equipment performance Testing of control rods was forward-looking = assessment of operability vs past compliance i . No attempt was made to disguise the testing = practice Final Scram test data was the time used to = verify compliance even if the control rod got slower A change in philosophy with respect to using = As-Found data was evident The change in testing philosophy is what led to = the 10/15/92 PRO . . . . . . _ - . _.

,. . . . _ . .. ' '. .. . . .- .. . .. ! REVIEW OF AS-FOUND DATA RECORDS

, & Single rod scram testing was reviewed with no = violation to the Technical Specifications noted

Using As-Left data vs As-found data had a = relatively minor impact on the scram times , A review- of some of the 2 x 2 arrays was = conducted - no other discrepancies noted Full scram data have consistently shown faster = times Full scram data questioned due to recorder- = delay in the start-up time ' Correcting for the recorder start-up delay = time to previous full scram data - no violations ' of the Technical Specifications was noted ,

' '..;.. . - . t REVIEW OF THE TECHNICAL < SPECIFICATION COMPLIANCE . i PRO dated 10/15/92 needs to be re-evaluated; = team conclusion was that the plant should have been shut down Review of a 1984 memorandum appears to = have violated Technical Specifications Section 3.3.C.3 Apparent contradiction between 3.3.C.3 and = 4.3.C.1 The apparent contradiction appears to have = contributed to the failure to meet Technical Specifications during the 1984 refuel outage

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REVIEW OF- MANAGEMENT EXPECTATIONS i Plant management was aware of As-Left = method for determining Control Rod ' Operability Focus was on core wide average, not 2 x 2 = Plant management was aware of the change in = As-Left vs As-Found philosophy ' Plant management was briefed by R/CE and = expectations were that 4/6/93 scram time j would meet Tech Spec limits ) - YNSD Nuclear Department was- asked to = evaluate slow scram times to the Safety Analysis . _ - _

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' . c; , - . , SIGNIFICANT CORRECTIVFs ACTION REPORT TASK TEAM #3 = Root Cause o The cause of both the PRO issue and the As- Left vs As-Found interpretation is one of personnel error, misinterpretation of information Contributing Causes, Similar Events and Other = Problems o The failure to identify, nor implement correction to the full scram time data based on the non-conservative start-up delay time of the test recorders was found to be attributed to l inadequate QC o Multiple retest of individual control rods prior to data analysis has been an accepted practice at Vermont Yankee. This approach to Control Rod Surveillance testing is not described in testing procedure OP 4424. This contributing cause is attributed to an incomplete procedure.

- ' . . . .**O . SIGNIFICANT CORRECTIVE ACTION REPORT RECOMMENDATIONS , Prohibit the use of the 30-pen recorders for full scram data = collection Tech Spec LCO 3.3.C.3 applies to core wide average and 2 x = 2 array scram time Procedure OP 4424 should require explicit review of LCO = ' 3.3.C.3 and 3.3.F Specific criteria shall be established for the use of As-Found = vs As-Left testing criteria Establish specific procedures for surveillance testing and = operability testing post refueling outage Establish specific guidelines and expectations for performance = trending Improve scram time data record keeping = Re-Evaluate Technical Specifications Section 3.3.C and 4.3.C = Train Vermont Yankee personnel on the various issues = identified in the CAR All departments to evaluate their surveillance philosophy (As- = Found vs As-Left) Multiple follow-up recommendations were also made to revisit = the correction actions for effectiveness

'..;*.. , , , _ . PERFORMANCE REVIEW COMMITTEE O PURPOSE O METHODS = SECURITY = LOR i ' = EDG i ! = FIRE SEALS = SCRAM TIMING

QA REPORTS = = NRC REPORTS CONSULTANT REPORTS = O FINDINGS . O ACTIONS

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.y, . , . . . . . . - SUMMARY , i SIGNIFICANT REGULATORY SIGNIFICANCE \\ MINIMAL SAFETY SIGNIFICANCE SELF IDENTIFIED IMMEDIATE NOTIFICATION

THOROUGH, AGGRESSIVE CORRECTIVE ACTIONS ' i ' EVENT SPECIFIC COMPANY GENERIC . i ' l l l- .. l \\ - -. . - - . . - . - . - - <

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i r - i . > I ! k SAFETY SIGNIFICANCE

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P ~ VERMONT YANKEE ~ i i i , SCRAM PERFORMANCE 1

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_ _ _ _ . , - . , . . 1 1 . PRESENTATION OUTLINE Review of Tech. Spec. requirements -

Basis for Tech. Spec. requirements - i Recap of scram performance - - Significance of scram performance on - ' MCPR limits j . Conclusions - , e

. . . .- . .. ' . ) - . , TECH. SPEC. REQUIREMENTS i 1 . f Average scram times - (single rod testing)

i l , MST - ? i ! !

Drop-Out of % Inserted From Avg. Scram insertion l Position Fully Withdrawn Time (sec)

.. i 46 4.51 0.358

36 25.34 0.91 2

26 46.18 1.468 i 06 87.84 2.686 - ! , ! .! 67B - , i ! Drop-Out of % Inserted From Avg. Scram insertion j Position Fully Withdrawn Time (sec) 46 4.51 0.358 j 36 25.34 1.096 26 46.18 1.860

06 87.84 3.419 l . i ) !

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. , - i TECH. SPEC. REQUIREMENTS (Continued) f Average of three' fastest of all groups of - four in 2 x 2 array l l MST -

Drop-Out of % Inserted From Avg. Scram insertion Position Fully Withdrawn Time (sec) 46 4.51 0.379 36 25.34 0.967 26 46.18 1.556 06 87.84 2.848 - 67B - Drop-Out of % inserted From Avg. Scram insertion Position Fully Withdrawn _ Time (sec) 46 4.51 0.379 36 25.34 1.164 26 46.18 1.971 06 87.84 3.624 . .

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- .. ' . , > . ' BASIS FOR TECH. SPEC. REQUIREMENT i - > For most transient scenarios - , important for rods to insert

Time response important only for " fast" - transients (20% - 70% insertion) , Turbine trip w/o bypass

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Generator load rejection - ' - , . . Rapid MSIV closure - . a Results from " fast" transients establish 1 - MCPR limits for cycle exposures > EOFPL . - 1000' MWD /ST (all rods out)- 4

Scram times associated with fast - transients are not a concern at earlier exposures (some rod insertion) ' ' . .- . - . ..

l. ' ' 4 i - i BASIS FOR TECH. SPEC. REQUIREMENT (Continued) , Average scram time - Assumed in MCPR limit 4 determination for - fast transients 2 x 2 Scram Time - Assures local scram performance does - not deviate significantly from average Assures assumption on core average - , scram reactivity is maintained l

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i i . RECAP OF SCRAM PERFORMANCE l l q . t i ! i Notch 46 (4.51%) only position 1 - Tech. Spec. exceeded

! ! ' Average

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- ~ -i . , Max deviation i - .011 sec at notch 46 (.369 vs. 358) ] l ! ! 2 x 2 Array - ! ! Max single deviation

- .039 sec at notch 46 (.418 vs. 379) . 5 I f i - - - - . . . . __ _ . _ . . . - - - . . . . _ _ . . , _ _ , . . !

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SIGNIFICANCE OF SCRAM PERFORMANCE ON MCPR LIMITS- i - ) Evaluation used NRC approved analytical - methods for fast transients j

Turbine trip w/o bypass was evaluated by - modifying scram curve at 46 notch j position ' MCPR performance was quantified for ' . insertion time delays at notch 46 up to .50 seconds .4 4 . I . . . . . .- - . - . . - . - - . .J

E. E O ~) A . c e SCRAM RESPONSE 67B SCRAM SPEED 25 % $ $ - 00 q . .. D O.5 NDs

1 .. 20

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, 6 4 i 1 . . A , - , . . 0.n 0.2g <$ 0.lg 1.0 DQgISGComog 9 % 1 - - , - . . , - - - - - - , . . - - , - , , . . - , , - - . - . . - -n.....,.-.--.. , , . , , , . , . , , , - - . . . , , - - , ,,n,,,w,,;-n., ,,n w.w, ~ , , - - - -,.n- , .

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\\ MCPR RESULTS FOR TURBINE TRIP - i I t - MCPR I Insertion To j Notch 46 MST 67B l t Tech. Spec. .358 1.21 1.24 Modified Curve 0.40 1.21 1.24 (46 Notch) . " . 0.50 1.22 1.26 ., Max difference of .02 for 0.50 sec is offset.by ' initial power. Analysis performed at 104.5% of rated . 2.5% power is worth .02 ACPR . . . e er W v~-,m- ,

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.. - - a. . t c , CONCLUSION . l i ! Delay in rod insertion to notch '46 from

- ' .358 sec >.500 insignificant impact on MCPR or peak system pressure i i Insertion time limits for positions between ) - 70% are important for fast i 20% - transients near EOFPL exposures i i 4 Consistent with fact that some plants do > - not have T.S. at notch 46 position (4.5%) , . - -. - ? }}