IR 05000245/1993016
| ML20046B020 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/22/1993 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20046B014 | List: |
| References | |
| 50-245-93-16, 50-336-93-11, 50-423-93-13, NUDOCS 9308030015 | |
| Download: ML20046B020 (32) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report / Docket Nos.:
50-245/93-16 50-336/93-11 50-423/93-13 License Nos.:
DPR-21 DPR-65 NPF-49 Licensee:
Northeast Nuclear Energy Company P. O. Box 270 Hartford, CT 06141-0270 Facility:
Millstone Nuclear Power Station, Units 1, 2, and 3 Inspection at:
Waterford, CT Dates:
May 19,1993 - June 29,1993 Inspectors:
P. D. Swetland, Senior Resident Inspector K. S. Kolaczyk, Resident Inspector, Unit 1 D. A. Dempsey, Resident Inspector, Unit 2 R. J. Arrighi, Resident Inspector, Unit 3 Approved by:
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Lawrence T. Doerflein, Chief j
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Reactor Projects Section 4A, DRP Scope: NRC resident inspection of activities in the areas of plant operations, radiological controls, maintenance, surveillance, security, licensee self-assessment, and periodic reports.
The inspectors reviewed plant operations during periods of backshifts (evening shifts) and deep backshifts (weekends, holidays, and midnight shifts). Coverage was provided for 37 l
hours during evening backshifts and 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> during deep backshifts.
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Results: See Executive Summary
e 930B030015 930722 PDR ADOCK 05000245 O
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EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/93-16; 336/93-11; 423/93-13
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Plant Operations Except for power reductions for routine testing and maintenance, Unit 1 operated at full power during the inspection period.
Unit 2 was operating at full power at the beginning of the inspection period. During main condenser thermal backwashing on May 24, a reactor trip occurred when the main turbine tripped on high stator cooling temperature. Inadequate monitoring of service water system temperature resulted in high operating temperatures in safety-related and non safety-related
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systems. An unresolved item was identified regarding operation of safety-related cooling water systems on May 24, beycad design basis temperature limits. During the ensuing reactor start-up on May 25, the licensee was initially unable to achieve criticality. The
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problem was caused by inaccuracies in the fuel vendor supplied core reactivity calculation curves, and a poor choice of estimated critical rod position which precluded operators from -
using the full nine percent critical rod position accuracy window. A reactor trip on high pressurizer pressure occurred on June 3, due to an appcrent malfunction of the turbine electrical-hydraulic control system. Operator response to the trips was very good. The plant returned to full power on June 5.
Unit 3 operated at full power during the inspection period with the exception of a minor power reduction for main condenser thermal backwashing.
Radiological Controls
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Enforcement discretion was exercised for violation of a Unit 2 technical specification high j
radiation area boundary and for failure to document pre-access radiation surveys. Licensee i
root cause evaluations and corrective actions were timely and comprehensive.
i Maintenance / Surveillance Generally good maintenance practices were observed at each unit. An underground i
instrument air line to the Unit 3 intake structure was severed during excavation for a new office building. Prompt operator action avoided potential plant transients which could have resulted. The incident emphasized the importance of maintaining accurate plant drawings.
i A violation was cited at Unit 2 for failure to follow procedure during the performance of an inservice test of boric acid system recirculation valves. The cause of the procedure adherence problem, the valve test failure, and clarification of procedure acceptance criteria are unresolved.
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Safety AssessmenUQuality Verification Two violations were cited at Unit 2 regarding failure to follow procedures during operation of technical specification radiation monitors. Both violations were cited, in part, because of
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inadequate corrective actions for previous violations. Weaknesses in the performance of plant equipment operator shift turnovers, communication of off-normal equipment configuration to shift supervision, and performance of log reviews also were identified.
Examples of inadequate scope of plant incident report investigations at Unit 2 were identified.
At Unit 3 creation of a task force to review reactor protection and engineered safety features system overlap testing deficiencies was an appropriate response to previous, narrowly focused corrective actions.
An apparent weakness in programs for review of industry operating experience contributed to the belated identification of problems involving operability of the Unit 3 supplementary leakage collection and release system under design basis temperature conditions. Licensee evaluation of emergency diesel generator fuel oil capacity did not recognize that the plant design basis was not met and that an unreviewed safety question per 10 CFR 50.59 existed.
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SUMMARY OF FACILITY ACTIVITIES
Millstone Unit I started the report period at 100 percent power. Minor power reductions to 80 percent were conducted on a planned basis to perform condenser backwashing and turbine control valve, turbine stop valve, and main steam isolation valve testing. On June 8 and June 12, power was reduced to 80 percent and 62 percent, respectively, to repair tube leaks in a main condenser waterbox. Power was reduced to 40 percent on June 16 to clean the 'A'
reactor recirculation pump motor generator lube oil suction filter. At the end of the inspection period, the plant was at full power.
Millstone Unit 2 was operating at full power at the beginning of the inspection period. On May 24, at 9:42 a.m., durir; thermal backwashing of the main condenser, the reactor tripped automatically when high service water temperature caused the main turbine to trip on high stator cooling water temperature. The plant was stabilized in Mode 3 (Hot Standby). On May 25, at 12:20 a.m., reactor startup commenced. However, the reactor failed to go critical with all control element assemblies (CEAs) fully withdrawn, and at 4:06 a.m., all CEAs were fully inserted. Reactor startup recommenced at 11:51 a.m., with a revised _
criticality estimate. Criticality was a hved at 12:58 p.m. Full power operation resumed on
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May 27 and continued until June 3, at 4:24 p.m., when the reactor tripped on high
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pressurizer pressure. The reactor was taken critical on June 4 at 7:45 a.m., and full power
operation was achieved on June 5 at 12:30 p.m. The unit operated at full power for the remainder of the inspection period.
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Millstone Unit 3 started the report period at 100 percent power. The plant operated at full power for the duration of the inspection peciod, except on June 20, when power was reduced
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to 90 percent for a short time to perform fhermal backwash of the condenser bays. In
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response to the Unit 2 trip during thermal backwashing, the service water temperatures at
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Unit 3 were monitored. No significant temperature increases were observed.
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2.0 PLANT OPERATIONS (IP 71707, 93702)
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2.1 Operational Safety Verification (All Units)
The inspectors performed selective examinations of control room activities, engineered safety features systems, plant equipment conditions, and problem identification systems. These reviews included attendance at periodic plant meetings and plant tours.
The inspectors made frequent tours of the control room to verify sufficient staffing, operator procedural adherence, operator cognizance of control room alarms and equipment status, conformance with technical specifications, and maintenance of control room logs. The inspectors observed control room operators respond to alarms and off-normal conditions.
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The inspectors verified safety system operability through independent reviews of: system configuration, outstanding trouble reports and event reports, and surveillance test results.
During system walkdowns, the inspectors made note of equipment condition, tagging, and the existence of installed jumpers, bypasses, and lifted leads. At Unit 3 the inspector checked the position of the hydrogen recombiner manual containment isolation valves. The inspector verified that the valves were correctly labeled and positioned as required by the applicable system drawing and valve lineup. The inspector also verified that the monthly (valve position) surveillance was being performed as required by plant technical specifications. No
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discrepancies were identified.
The accessible portions of plant areas were toured on a regular basis. The inspectors observed plant housekeeping conditions, general equipment conditions, and fire prevention practices. The inspectors also verified proper posting of contaminated, airborne, and radiation areas with respect to boundary identification and locking requirements. Selected aspects of security plan implementation were observed including site access controls, implementation of compensatory measures, and guard force response to alarms and degraded conditions.
2.2 Reactor Trip During Main Condenser Thermal Backwashing - Unit 2 On May 24,1993, with the plant operating at full power, a main turbine trip followed by a
reactor trip occurrcJ. The turbine tripped automatically on high generator stator cooling l
system temperature while operators were restoring the circulating water (CW) system from a 20-minute thermal backwash of the "B" main condenser waterbox. Operators promptly completed the post-trip actions required by Emergency Operating Procedure (EOP) 2525,
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" Standard Post Trip Actions," and stabilized the plant in the hot shutdown condition.
l Safety-related systems performed properly during the event. However, following the turbine j
trip, operators were unable to control steam generator levels with the feed regulating valves
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(FRVs). Rather than closing automatically, tire #1 steam generator FRV remained at the 55% open position, and the #2 steam generator FRV indicated 10% open. The operators
tripped the running main feed pump, closed the FRV blocking valves, and restored steam generator level using the auxiliary feedwater system. (Resolution of the FRV problems is detailed in Section 4.1 of this report.) The licensee notified off-site emergency response organizations and the NRC of the event in accordance with emergency plan implementing
procedures and NRC requirements. The inspector observed post-trip activities in the control i
room and noted that operators had responded properly to the trip.
Thermal backwashing of the 'B' waterbox is performed in accordance with Operating Procedure (OP) 2325A, " Circulating Water System," to control the growth of mussels in the intake bays and CW system. Water is pumped from the 'A' bay of the intake structure by the 'A' circulating water (CW) pump, through the 'A' condenser waterbo~ and back through the 'B' waterbox through an outlet cross-tie valve. The heated water 1 i proceeds from the j
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'B' water box to the 'B' intake bay through the suction of the secured 'B' CW pump. The two safety-related service water trains are aligned to unaffected intake bays in order to maintain normal cooling capability to the associated reactor building closed cooling water (RBCCW) and turbine building closed cooling water (TBCCW) system heat exchangers.
The CW system lineup was completed at 9:10 a.m., on May 24, and at 9:20 a.m., the required 'B' condenser outlet temperature of 110 degrees Fahrenheit (*F) was attained.
Niantic Bay, the ultimate heat sink, was 52'F, with a low, slack tide. The RBCCW and
TBCCW heat exchangers were aligned in accordance with OP-2325A, three TBCCW pumps were running, and the TBCCW heat exchanger service water inlet valves were throttled 30%
open pursuant to an operations department night order. The operators monitored CW system and condenser performance data, but did not closely monitor senrice water system temperature. Approximately five minutes after the backwash was started, service water temperatures into all of the heat exchangers began to rise and operators noted increases in TBCCW and RBCCW heat exchanger outlet temperatures. At 9:35 a.m., a turbine hydrogen seal oil system high temperature alarm was received in the control room and operators were dispatched to increase service water system flow to the TBCCW heat exchangers by opening the inle. 5rottle valves to the 40% limit specified by procedure. The alarm cleared at 9:37 a.m., but cooling water temperatures continued to rise and other steam plant component temperature alarms were received intermittently. Following completion of the backwash at 9:40 a.m., the operators began to restore the CW system lineup to normal. At 9:43 a.m.,
the turbine tripped. Cooling water system temperatures peaked at approximately 9:45 a.m.,
then dropped to normal post-trip levels.
The intake structure bays are physically separated but interconnected by fish passages located on the Niantic Bay side of the travelling screens. Each passage is about 27 feet high and five feet wide. The CW pump suctions are near the bottom of the bays, while the service water pump suctions are located approximately eight feet higher. Since cooling water system temperatures were not trended by the licensee during thermal backwashing, the licensee was unable to identify the cause of the service water system temperature transient definitively.
The licensee postulated that the slack tidal conditions had reduced circulation of water j
between the intake bays and Niantic Bay and permitted the hot (ll5*F) water to migrate upward and into the adjoining bays through the fish passages. The hot water recirculated preferentially to the higher service water pump suctions. The following peak temperatures were observed during the event:
Component Temnerature ( F)
"A" CW pump suction
"A" service water pump suction
"C" CW pump suction
"C" service water pump suction
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"B" TBCCV' heat exchanger outlet 110 i
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"C" TBCCW heat exchanger outlet 105
"A" RBCCW heat exchanger outlet
"C" RBCCW heat exchanger outlet
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After the trip, the licensee also found that the stator cooling system heat exchanger outlet valve throttle positions had been set lower than previously (15 and 30 degrees, respectively, from fully shut vice 40 to 45 degrees). The system valve lineup sheet for these valves did not specify a particular throttle setting. Stator cooling system temperature was observed to increase from 145 F to 167 F during the event, but the turbine trip setpoint, which comes
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from a different sensor than the indicator, is 178 F. The licensee subsequently determined that the resistance temperature detector (RTD) associated with the indicator had been installed improperly into its pipe well during plant construction, and had indicated approximately 11 F lower than actual temperature. The RTD installation error was corrected; the trip setpoint was verified; and the correct throttle position for the heat exchanger outlet valves was added to the system valve lineup.
l In order to assess plant conditions and operator performance prior to the trip, the inspector interviewed licensee personnel; and reviewed operating procedures, the sequence of events and computer trend reports, and licensee trip assessment documents. The inspector noted that operators had aligned the CW, service water, RBCCW and TBCCW systems properly and i
had monitored CW system performance in accordance with procedure requirements.
Operators had observed increasing temperatures and had taken action to increase service water flow to the TBCCW heat exchangers. During interviews with the inspector, the operators stated their belief that the system temperature increases had been under control during the backwash, and that the problems had occurred during CW system restoration. However, after reviewing plant data, the inspector concluded that cooling water system temperatures had increased steadily throughout the evolution. The inspector noted that Procedure OP-2325A did not provide any guidance regarding the potential for increased service water temperature or direct any special monitoring of cooling water system parameters during thermal backwashing.
Procedure OP-2326A, " Service Water System," precaution Step 4.9, requires that RBCCW temperature at the outlet of the RBCCW heat exchangers shall be maintained less than 85 F at all times. This requirement is consistent with the design assumptions contained in the Final Safety Analysis Report and recent licensee analyses conducted pursuant to NRC Generic Letter 89-13, " Service Water System Problems Affecting Safety-Related Equipment." The inspector noted that this limit had been exceeded eight minutes into the thermal backwash evolution and persisted without operator intervention until approximately five minutes after the reactor trip. The inspector concluded that the operators had failed to effectively monitor and maintain RBCCW temperature in accordance with Procedure OP-232.6A. Technical Specification (TS) 3.7.11 limits the average water temperature of the ultimate heat sink to 75'F. The inspector considered the intake structure bays to be an integral part of the ultimate heat sink, and that operation with intake bay temperature above this limit would require the licensee to take the compensatory measures specified by the TS action statement
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(TSAS). The operators did not recognize that TS 3.7.11 had not been met and failed to enter the TSAS which requires the plant to be placed in hot standby within six hours. Since the backwash evolution lasted less than one hour no violation of the TS limiting condition for -
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operation occurred.
The licensee suspended future condenser thermal backwashing pending evaluation of the cause
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of the event and development of corrective actions to prevent recurrence. Blocking of the intake structure fish passages is being evaluated. Procedure changes have been proposed to
alert operators to the potential for higher than normal service water temperatures, and to enhance monitoring of system performance. Temperature gradients in the intake bays will be trended during the evolution, and acceptable tidal conditions will be specified. The licensee is considering a limit of 95*F at the service water inlet of the TBCCW and RBCCW heat exchangers. The inspector was concerned that operation of the service water system with inlet temperatures greater than the TS limit could adversely affect the performance of safety-related components (e.g. emergency diesel generators, containment air recirculation units,
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emergency core cooling pump room coolers, and vital switchgear room coolers). No licensee evahiation existed addressing the adverse consequences of operating the service water system outside of the design basis temperature of 75 F (accident analysis bounding parameters). The inspector concluded that while the licensee may be able to demonstrate the operability of safety-related components under elevated service water /RBCCW temperature conditions for a limited period of time, that evaluation must be completed prior to voluntarily entering the
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TSAS for ultimate heat sink operability. In addition, controls to assure that accident analysis assumptions regarding cooling water system temperatures are maintained need to be established. The licensee acknowledged these concerns and imposed a service water inlet
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temperature limit of 75 F on future thermal backwashes pending further evaluation. The
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inspector also noted that the licensee's post-trip discussions of operator performance during the thermal backwash did not identify the design temperature limit issues raised above. This l
issue remains unresolved (50-336/93-11-001) pending NRC review of the licensee's evaluation of elevated cooling water temperatures and completion of planned corrective actions.
2.3 Reactor Startup After Turbine Trip - Unit 2 On May 25,1993, at 12:20 a.m., the licensee commenced a reactor startup from the automatic trip which occurred the previous day. The inspector reviewed the licensee's post-trip evaluation, performed in accordance with Procedure OP-2671, " Duty Officer Requirements After A Reactor Trip Or ESF Actuation," and discussed the results with licensee management. The inspector concluded that the licensee had identified the cause of the reactor trip and that the corrective actions were adequate to support a safe return to power operation. The inspector noted that the licensee intended to limit reactor power to the capacity of the feedwater control system bypass valves pending completion of maintenance on the #2 steam generator feed regulating valve.
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The licensee's estimated critical position (ECP) calculation predicted (within 0.9% delta rho)
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that reactor criticality would occur with control element assembly (CEA) regulating group 7 withdrawn approximately 90 steps and a reactor coolant system (RCS) boron concentration of
about 775 parts per million. At 2:15 a.m., all CEAs were fully withdrawn from the core, but the reactor remained suberitical with approximately 0.5% delta rho remaining to the upper ECP limit. After reverifying RCS boron concentration through two independent analyses, the regulating CEA groups were inserted and the reactor shutdown margin was verified. After recalculating the ECP and finding no significant differences from the original calculations, operators inserted the shutdown CEA groups and borated the RCS to the required hot shutdown concentration. Thes actions were accomplished by 5:25 a.m.
The licensee reactor engineer checked that no data transcription errors between the Cycle 12
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Startup and Operations Report and the ECP calculation procedure had occurred, and
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compared the Cycle 12 report with the Cycle 11 Startup and Operations Report. The J
comparison revealed differences in transient Xenon worth data for essentially similar reactor
cores; Cycle 11 Xenon defect (Peak Xenon worth minus Equilibrium Xenon worth) was predicted to be 2.41% delta rho, while the Cycle 12 Xenon defect was 1.48% delta rho.
i Thus the new curves underpredicted transient Xenon worth at the time of the startup.
l Shutdown margin calculations remained valid because actual Xenon concentration in the core was greater than that predicted by the curves. The plant operations review committee reviewed the evaluation and approved another reactor startup targeting criticality approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the reactor trip with CEA regulating group 7 at zero steps. At this time, Xenon in the core would be at the 100% power equilibrium concentration whichever curve was used. The reactor was restarted at 11:51 a.m., and criticality was achieved with regulating group 7 at 46 steps (within 0.35% delta rho of the ECP).
The inspector discussed the Xenon curve anomalies with the reactor engineer and concluded that the licensee's evaluation and decision to restart the reactor was safe and appropriate.
The licensee is consulting with the fuel vendor, Siemans Nuclear Power Corporation, regarding the transient Xenon curves. Siemans believes that the new curves are accurate, and is examining Unit 2 startup data to benchmark its fuel temperature defect calculations as a potential cause of the problem. The inspector concluded, however, that the existing curves provided conservative estimates of reactor core response during startup. The inspector witnessed portions of the reactor startup in the control room. Procedure prerequisites and technical specification requirements were satisfied, and the operators properly performed the approach to criticality.
While placing the main generator in service later in the day, the turbine tripped automatically on overcurrent when operators closed the generator field breaker. The overcurrent was caused by mismatched settings between the manual DC voltage regulator and the automatic AC voltage regulator. Operations Procedure OP-2324A, " Turbine Generator and Exciter,"
required that the manual DC regulator be checked at the lower electrical limit prior to closing the field breaker, but did not direct operators to verify that the automatic AC regulator was also at the lower limit. The licensee added this verification step to the procedure to prevent
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- l recurrence. The inspector noted that the procedures provide no explicit direction for post-trip setup for main generator restart, and that the need to run the automatic AC voltage regulator to the minimum stop during normal shutdown still is not addressed in Procedure OP-2324A.
The licensee agreed to evaluate further procedure enhancements. The inspector had no
further questions concerning the startup.
2.4 Reactor Trip On High Pressurizer Pressure - Unit 2 l
On June 3,1993, at 4:24 p.m., with the plant operating at full power, an automatic reactor trip on high pressurizer pressure occurred. The transient was initiated by quick closure of the
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main turbine intercept and control valves, apparently caused by a malfunction of the j
electrical-hydraulic control (EHC) system. The rapid decrease in turbine power caused a i
primary-to-secondary system load imbalance which rapidly increased reactor coolant system I
pressure to the reactor protection system (RPS) setpoint. The pressure transient was terminated by the reactor trip and opening of both pressurizer power-operated relief valves -
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(PORVs). Several mein steam safety valves also lifted, relieving the high pressure in the steam generators.
I After the reactor trip, operators implemented the required actions of Emergency Operating Procedures EOP-2525, " Reactor Trip," and EOP-2526, " Reactor Trip Recovery." The PORV block valves were closed per EOP-2525 to stabilize RCS pressure. ~ No abnormal conditions were observed during performance of the EOP safety function status checks, and all safety systems functioned properly. The licensee notified the NRC Operations Center of the event in a timely fashion pursuant to 10 CFR 50.72. The inspector responded to the control room and observed operator response to the event. Operator performance was professional; procedures were followed, and communications were formal. The shift supervisor and senior control operator demonstrated good command and control of the post-trip activities. The inspector subsequently verified through review of sequence of events recorder data that no safety equipment problems had occurred.
The licensee assembled a post-event evaluation review team in accordance with Procedure OP-2671, " Unit 2 Duty Officer Trip Determination Check List." Representatives from Units 1 and 3 also responded to the event, and Unit 3 personnel briefed the team on past EHC system problems and findings at that unit. Licensee troubleshooting efforts, in which a main turbine vendor representative participated, unsuccessfully attempted to correlate known turbine valve response with the EHC alarms which had been received, and the system control schemes. Inspection of the EHC cabinets and monitoring of components revealed no abnormalities. During operator debriefings the licensee found that a plant equipment operator had opened the EHC cabinet for routine inspection immediately prior to the trip. Since the EHC system is very sensitive to jarring, the licensee speculated that the system may have been perturbed when the PEO reclosed the cabir.et doors. Subsequently, administrative controls were established to limit operation of the cabinet doors. Since the root cause of the trip could not be determined conclusively, the plant operations review committee met and concurred in the decision to restart the reactor, as required by licensee administrative
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procedures. The inspector considered the licensee's troubleshooting and event review efforts to have been thorough and reasonable, and identified no safety concerns. Reactor startup commenced on June 4, at 4:25 a.m., and criticality was achieved three hours later. Full power operation was achieved on June 5, at 12:30 p.m.
3.0 RADIOLOGICAL CONTROLS (71707)
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3.1 Violation of IIigh Radiation Area Boundary - Unit 2 On the evening of April 27,1993, the licensee identified that on April 23 a plant equipment operator (PEO) had violated a locked technical specification (TS) high radiation area (HRA)
boundary while gaining access to valve 2-CH-717, located in the overhead area of the volume
control tank (VCT) cubicle. The valve is reached by a permanently installed ladder. The ladder was posted conspicuously as a TS HRA boundary by two signs, and was blocked by a
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board mounted vertically, and chained and locked to the rungs. Through interviews with the i
personnel involved, the licensee established that the PEO was able to climb the ladder by -
side-stepping the board. A quality services department (QSD) auditor, who was accompanying the PEO at the time, recognized that the ladder was a locked HRA boundary,
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but did not react quickly enough to forestall the incident. The individuals estimated that the -
i activity took place in less than one minute, and no radiological overexposure occurred. The licensee immediately initiated an investigation of the incident.
On April 27, health physics (HP) personnel performed a survey of the entire area and ascertained that operating conditions in the VCT cubicle were similar to that which had existed on April 23. The radiation level at valve CH-717 was approximately 150 millirem per hour. Also on April 27, the PEO's dosimetry was processed which indicated the PEO had received a total exposure of approximately 2.6 millirem for the quarter beginning April 1. This total was consistent with the radiation levels measured at the valve and the statements of the PEO and the QSD auditor. The licensee restricted the PEO's access to radiologically controlled areas (RCAs) pending completion of its investigation and of remedial corrective actions. HP supervision discussed the incident with licensee management on April 28, and briefings of all operations and HP shift crews concerning HRA access requirements were completed by May 5. The PEO's RCA access was restored following successful completion a comprehensive radiological fundamentals examination. The inspector concluded
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that these short-term corrective actions were acceptable.
The inspector questioned the Unit 2 HP supervisor regarding the possibility of other unauthorized entries to the VCT overhead area. The supervisor reviewed operations, chemistry, and HP records and logs and found that 24 VCT gas samples had been taken since j
January 1993, when the ladder had been posted and locked. Although the data could not be correlated definitively, the licensee concluded that the incident on April 23 had been an isolated case. Through discussion with the supervisor, the inspector concluded that the investigation had been thorough, and that the finding was reasonable.
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In the course of the investigation, the HP supervisor found that on previous entries to the VCT overhead area, HP personnel had not documented the results of pre-access rafation surveys. The Unit 2 HP staff was directed to document all surveys used to set radiological controls, to confirm the appropriateness of existing controls, and to control personnel access to RCAs. The HP supervisors for Units 1 and 3 also were notified of the findings. The supervisor also determined that the existing method of using two RWPs (one for general
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access and one for TS HRAs) for operations department personnel was cumbersome, as it often required a PEO to exit an RCA unnecessarily to log onto the locked HRA permit. The permits were consolidated onto a single, comprehensive RWP. All operations shift crews were trained on the new permit during the week of June 20. The inspector reviewed the RWP, witnessed one briefing, and had no questions regarding the permit.
Through discussions with the PEO and the QSD auditor, the inspector found that the auditor had questioned the PEO about the HRA boundary immediately after the incident. The PEO
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stated to the auditor (and subsequently to his supervisor and the inspector) that the boundary l
had not been posted during his training, and that he believed that the ladder was only a locked HRA when the board was positioned perpendicular to the ladder to completely block the rungs. The QSD auditor initially accepted this response, but brought it to the attention of his supervisor on April 27. The inspector considered that the appropriate action would have been to seek guidance promptly from HP supervision immediately after the incident.
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However, the inspector concluded that the PEO had not violated the TS HRA boundary intentionally.
The inspector concluded that on April 23, the PEO did not notify HP personnel to perform a pre-entry survey of the VCT overhead area, did not receive a briefing of radiological conditions, and did not properly log onto the appropriate RWP prior to gaining access to valve 2-CH-717. These actions were a violation of Technical Specification 6.12.1 concerning administrative control of locked HRAs. The inspector also concluded that the failure of HP personnel to maintain records of surveys performed to sapport entries into this locked HRA was a violation of 10 CFR 20.401, which requires, in part, that surveys be documented.
However, the inspector found that the licensee's investigation was aggressive and thorough, and that the corrective actions were appropriate to the causes, comprehensive and timely.
The inspector considered the finding concerning RWPs particularly noteworthy, as demonstrating the value of thorough root cause evaluations. Therefore, since the requirements for the exercise of enforcement discretion contained in Section VII.B of 10 CFR Part 2, Appendix C (Enforcement Policy) were met, the violations will not be cited, l
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4.0 MAINTENANCE (IP 62703)
The inspectors observed and reviewed selected portions of preventive and corrective maintenance to verify adherence to regulations, administrative control procedures and
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appropriate maintenance procedures; adherence to codes and standards, proper QA/QC involvement, proper use of bypass jumpers and safety tags, adequate personnel protection, and appropriate equipment alignment and retest. The inspectors reviewed portions of the following work activities:
- M2-93-05406 Clean and check contact resistance of turbine trip / feed regulating valve relays
- M2-93-07796 Clean, adjust, and test valve 2-CH-510
- M2-93-07797 Clean, adjust, and test valve 2-CH-511 i
- M3-93-04058 Six month PM, 'B' quench spray pump oil change
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- M3-93-Il543 UT 3*CCI-ElB piping
The inspectors determined that the maintenance activities were performed well. Details of the inspector's observations are provided in report Sections 4.1 and 4.2.
4.1 Feedwater Regulating Valve Maintenance - Unit 2 During the reactor trip on May 24,1993, both steam generator feedwater regulating valves (FRVs) failed to operate automatically as designed; #1 FRV stuck at 55% open and #2 FRV indicated 10% open. The inspector witnessed licensee troubleshooting and repair activities associated with both valves. The licensee found that on the #1 FRV a small handwheel which locks the main valve handwheel into the proper position for remote operation had j
vibrated loose allowing the valve to shift to the local manual mode of operation. in this condition remote operation of the valve is precluded. The safety significance of the condition was mitigated by the ability to shut the FRV blocking valve (which was done during the event), and the main feedwater pump discharge valve. Both of these valves also close automatically to terminate feedwater addition to the steam generator if a main steamline isolation signal occurs. To prevent recurrence, the licensee installed a locking device-on the handwheels.
The #2 FRV was found to operate approximately three-eighths of an inch short of full closure, accounting for the post-trip increase in steam generator level observed by the operators. Under automated work orders (AWO) M2-93-07232 and M2-93-07245, maintenance personnel adjusted the valve operator and reset the valve position indicator, and instrumentation and controls technicians recalibrated the valve controller. Operational checks i
of valve performance were performed successfully and the valve was restored to service on May 25.
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The inspector verified that proper maintenance boundaries had been established and that maintenance personnel had the AWOs and proper procedures at the job site. The mechanics j
were very knowledgeable regarding the valve, followed the procedures appropriately, and,
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overall, performed the maintenance in a professional manner. Interface with operations
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personnel was good, and management oversight of the activity was noted.
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4.2 Instrumentation Air Line Break - Unit 3
On May 25,1993, the instrument air system (IAS) line to the Unit 3 intake structure was i
severed. The IAS trouble alarm annunciated in the control room as a result of the line break.
A plant equipment operator was dispatched to the turbine building to investigate air compressor operation and noted that the 'A' instrument air compressor had tripped on high temperature and that the 'B' compressor had automatically started. Within a couple of
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minutes of receipt of the alarm, construction personnel notified the shift supervisor (SS) of an i
i air line break to the intake structure. In response, the SS isolated the air line. Instrument air pressure was noted to have decreased from 105 psig to approximately 83 psig.
J The air line was severed by a backhoe bucket during excavation for a new administrative office building. The licensee determined that adequate precautions had not been taken by construction personnel prior to removing an outside light pedestal. An as-built drawing of the area correctly showed the location of the pedestal in relation to the air lines; however, this drawing was considered unreliable by the personnel involved since it had proved to be inaccurate with respect to a previously uncovered water line. Another drawing which was being used as an "as-built" drawing did not adequately show the relation of the light pedestal to the air lines. Based on this inaccurate drawing, construction personnel assumed that the light pedestal would not be located as close to the air lines and felt that further precautions, such as hand digging, were not warranted. In addition, the licensee stated that the air line was not installed using accepted construction practices (i.e., no sand around the line nor any indicators such as ribbon above them to indicate their presence).
As a result of the air line break to the intake structure, differential pressure indication across the traveling water screen was lost. This results in the failure of the automatic starting
function of the traveling water screen and the loss of the automatic trip function of the screen on high differential pressure. In addition, the high speed debris spray, for removal of debris from the traveling water screens, was lost. In response to the loss of these functions, operations personnel placed the traveling water screens in slow speed and opened the trash rack hatches to monitor conditions (seaweed) at the intake structure. The severed air line was repaired and instrument air restored to the intake structure in approximately nine hours.
As corrective action to prevent recurrence, construction personnel involved were reminded of the necessity of locating underground utilities prior to performing work that could damage them. Prior to additional excavation work for the construction of the administrative building, other known underground systems were more definitively located, both in elevation and plan location. Disciplinary action was taken for those supervisory personnel directly involved.
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Instrument air provides air for pneumatic instrumentation and valve operation for components inside and outside containment, and for breathing air. The system is composed of two 100 percent capacity compressors. One compressor is in operation to maintain receiver pressure within a prescribed pressure band and the other is in a standby mode and will start whenever i
receiver pressure drops below a certain setpoint. At low air pressure, the service air system supplies the instrument air header. Upon a loss of instrument air, various controls or control features are lost requiring the plant to be in accordance with Abnormal Operating Procedure (AOP) 3562, and placed in a stable condition.
Although the event had the potential of resulting in a plant transient had air pressure not been able to be maintained, the actual event had minimal safety consequence. The inspector noted the shift supervisor took prompt action in response to the IAS trouble annunciator and in the isolation of the IAS line when notified of the problem. The inspector considered the licensee response to the event and the corrective actions to be good. The inspector had no further
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questions.
5.0 SURVEILLANCE (IP 617.~6)
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The inspectors observed and reviewed selected portions of surve:llance tests, and reviewed test data, to verify adherence to procedures and technical specification limiting conditions for operation; proper removal and restoration of equipment; and, appropriate review and
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resolution of test deficiencies. The inspector reviewed portions of the following tests:
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- EN21203 Service Water Flow Test
- EN21004A Inverse Count Rate Calculation and Evaluation
- SP2669A Plant Equipment Operator Rounds
- SP2610E Main Steam Isolation Valve Closure Test I
- SP2404AW (RBCCW) Liquid Process Radiation Monitor, RM-6038, Functional Test
- SP3712AA Main Steam Isolation Valve Partial Stroke Test
- OP3346A Emergency Diesel Generator
- OP3211B Shipping New Fuel Assemblies Offsite Except as noted below, the inspectors determined that the st'rveillance activities observed were performed well. Details of the inspector's observations are provided in report Section 5.1.
5.1 Inservice Test Failure of Boric Acid Recirculation Valves - Unit 2
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On May 25,1993, a quarterly inservice test (IST) of boric acid pump recirculation valves 2-CH-510 and 2-CH-511 was performed pursuant to Surveillance Procedure SP-21131,
" Chemical and Volume Control System Operational Readiness Test." The valves passed the full stroke time test, but failed to travel promptly to the required position (shut) during the failure mode portion of the test. Valves 2-CH-510 and 2-CH-511 took approximately three
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i minutes and one and one-half minutes, respectively, to shut. The operations shift supervisor elected to reperform the test after exercising the valves. On the subsequent attempt, the l
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valves failed shut within approximately ten seconds, and the surveillance test was signed off as satisfactory. Trouble records were issued to maintenance to followup on the initial test failures. The test failures were identined by the work cc itrol center shift supervisor on June 3, during a review of trouble records, and a plant incident report was then initiated.
The boric acid (BA) pumps are part of a boron injection flow path to the reactor coolant system (RCS) required by technical specifications. In conjunction with gravity feed valves, i
i they provide a diverse method of delivering the contents of the boric acid storage tanks to the RCS via the charging pump suctions. Valves 2-CH-510 and 2-CH-511 are normally open, air-operated valves designed to fail shut upon loss of actuating air. The valves provide a recirculation flow path to test the BA pumps and to mix the contents of the storage tanks.
The valves close on receipt of a safety injection actuation signal from the engineered safety features system to prevent diversion of pump Gow to the charging pumps. Technical l
Specification 4.0.5.a requires the performance of an IST program in accordance with Section XI of the ASME Boiler and Pressure Vessel Code. Surveillance Procedure SP-21131, " Chemical and Volume Control System Operational Readiness Test," implements the
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IST program for valves 2-CH-510 and 2-CH-511. The failure mode test simulates loss of actuating air to the valves by isolating the supply and venting the valve actuators through the solenoid valves and supply regulators. The acceptance criterion is that the valves move
"promptly" to the failed position. Neither the procedure nor the IST program provide quantitative acceptance criteria for valve failure mode tests. Step 7.5.4 of Procedure
SP-21131 requires the following actions to be taken if either valve does not meet the acceptance criterion:
Immediately declare the valve inoperable
Initiate corrective action as required by technical specifications
Submit a plant incident report
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Nothy the IST coordinator or the engineering department inservice inspection
supervisor as soon as possible Submit a trouble report to maintenance
Continue or suspend testing as directed by the shift supervisor or s,pervising l
control operator The inspector discussed performance of the surveillance test with the shift supervisor, who
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stated that his decision to exercise the valves and to reperthrm the test had been based on
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experience that engineering would recommend immediate retest of the valves, and that he believed that the procedure authorized him to direct reperformance of the test. The inspector also attended the plant operations review committee (PORC) meeting on June 8, at which the
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initial PIR investigation results were presented. The PORC was informed by the IST
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coordinator that the decision not to declare the valves inoperable and initiate a PIR had been contrary to procedure requirements, and that a Notice of Violation had been issued by the NRC for a previous occurrence in 1991. The inspector observed no discussion of the f
personnel performance issues raised by the event.
The previous event and Notice of Violation referred to in the PORC nneting occurred in
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November 1991, and was documented in NRC inspection report 50-336/91-30. Licensee j
corrective actions for the violation included procedure changes to clarify the immediate
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actions required for an unsuccessful IST.21ve surveillance test, and operator training on the reasons for the changes to enhance understanding of IST program requirements. All operat ons personnel received the training by July 1992.
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Licensee failure to declare valves 2-CH-510 and 2-CH-511 inoperable, and to take other
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actions listed in Procedure SP-21331, is a violation of the licensee's IST program and NRC requirements. The inspector considereJ
- violation to be more significant because the activities involved licensed supervisory paonnel. The inspector also concluded that this -
i violation was one which could reasonably have been expected to have been prevented by corrective action for the previous violation. Therefore, the violation will be cited (50-336/93-11-002).
The licensee decided to perform the surveillance test on a monthly basis until successful valve performance justified a return to the quarterly schedule. The licensee retested the valves on June 15. Both initially failed to shut promptly and were declared inoperable. After exercising the valves, both operated properly. The inspector emphasized to the licensee that the intended monthly test cycle appeared to be inadequate, and that the continuing failures
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raised concern about the basis of valve operability pending identification and correction of the root cause of the failures. The licensee also was unable to determine the affect on the BA pump design basis flow rate to the charging pumps with the valves open. At the request of j
licensee engineering, the valves were left closed. The irspector witnessed licensee troubleshooting activities on June 17. The licensee was unable to duplicate the failure at that j
time. Procedure SP-21331 again was conducted on June 19 at which time valve 2-CH-511 was declared operable. Valve 2-CH-510 failed again and the recirculation line was isolated by a manual valve. At the end of the inspection period, the cause of test failures remained j
unidentified. This matter is unresolved pending determination of the correct design i
parameters for these valves, the cause of the failures, clarification of the acceptance cr;terion for failure mode tests, and NRC review of the licensee's corrective actions (50-336/93-11-003).
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l 6.0 SAFETY ASSESSMENT / QUALITY VERII;ICATION (IP 40500,90712,92700)
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6.1 Review of Written Reports l
The inspector reviewed periodic reports, special reports, and licensee event reports (LERs)
for root cause and safety rignificance determinations, and adequacy of corrective action. The inspectors determined whether further information was required and verified that the reporting requirements of 10 CFR 30.73, station administrative and operating procedures, and technical i
specifications 6.6 and 6.9 had been met. The following reports and LER's were reviewed:
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Unit 1 Monthly Operating Report for April 1993, dated May 11,1993 l
Unit 1 Monthly Operating Report for May 1993, dated June 9,1993.
l Unit 2 Monthly Operating Report for May 1993, dated June 8,1993.
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l Unit 3 Monthly Opemting Report for May 1993, dated June 8,1993.
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LER 50-245/93-03 discussed the failure of containment isolation valves to pass a Local Leak l
Rate Test. The event was reviewed in NRC Inspection report 50-245/93-13.
LER 50-245/93-04 wa9 written to document the discovery of missing seismic supports on the
instrument lines for th main steam line flow instrumentation at Unit 1. Initial NRC review and evaluation of the licensee's corrective actions was documented in NRC inspection report 50-245/93-13. Followup review is documented in Section 6.1.1 of this report. LER 50-24503-05 reported the discovery of an inoperable snubber during an inspection of tho
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l drywell enclosure. This issue was reviewed in NRC inspection report 50-245/93-13.
LER 50-336/93-04-01 was an update to an original report which discussed two reactor trips on low steam generator water level. The licensee reported completion of additional operator classroom and simulator training on main and auxiliary feedwater controls and steam generator water i ' response. The LER stated that all licensed operators had received the training, but the inspcctor determined that one individual had missed the simulator session and had been rescheduled for makeup in July 1993. The inspector considered the error to have be, i an oversight, but emphasized to the licensee the importance of accurate submittals.
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LER 50-336/93-09 discussed a technical specification noncompliance involving the reactor building closed cooling water system radiation monitor. The event is reviewed in Sections
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6.1.2 and 6.3 of this inspection report.
l LER 50-336/93-12 discussed a turbine and reactor trip which occurred during performance of main condenser thermal backwashing on May 24,1993. The event is reviewed in Section 2.2 of this inspection report. The inspector noted that the LER did not address the effect of elevated service water system temperature on safety-related systems and components served
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by the reactor building closed cooling water system. The inspector informed the licensee that the consequences of operating that system beyond the limits of the applicable operating procedure and the design assumptions stated in the Final Safety Analysis Report needed to be reported to the NRC in an LER. The licensee committed to update this LER.
LER 50-423/93-03 discussed inadequate testing of slave relays. This event is discussed in NRC inspection report 50-423/93-07.
6.1.1 Discovery of Missing Seismic Supports - Unit 1 (LER 50-245/93-04)
During the initial NRC review of the licensee's corrective actions, fne inspector noted that prior to plant startup, the licensee had not formally considered it the instrument lines had
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cycled excessively because of the missing seismic supports. The inspector was concerned that the excessive cycling could result in fatigue-induced cre; king of the instrument lines, and considered the licensee's engineering analysis of the potential for fatigue induced wear to be weak.
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Through further discussion with the licensee and review of LER 93-04, the inspector determined that the Unit 1 plant design basis does not specify that cyclic stresses be considered when conducting piping evaluations. Additionally, the engineers who walked i
down the unrestrained instrument lines prior to startup had judged that increased cyclic stresses were not a significant concern. Therefore, a detailed consideration of the potential effects of fatigue induced cmcking of the instrument lirs was not necessary, and the licensee's evaluation of the missing seismic supports was acceptable.
I 6.1.2 Inoperable Reactor Building Closed Cooling Water System Radiation Monitor - Unit 2 (LER 50-336/93-009)
During the midnight shift turnover between Mav 5 and May 6,1993, the oncoming and the ws (PEOs) questioned the status of process offgoing auxiliary building plant equipmerv
..a flow to reactor building closed ccoling w (RBC4 W) system radiation monitor RM-6038 Shortly after shift turnover, at due to an apparent conflict in shift ;ounds 10 - -...
1:00 a.m., on May 6, the PEO found the skid-mounted umple canister inlet and outlet isolation valves shut. The PEO restored flow to the radiation monitor and notified the control room. Subsequent service water system effluent grab samples indicated less than minimum detectable radioactivity (MDA). The licensee promptly initiated plant incident i
report (PIR) 2-93-88 to investigate the occurrence, and subsequently submitted to the NRC l
licensee event report (LER) 50-336/93409, dated June 4,1993.
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Unit 2 has no service water system effluent radiation monitor. As an alternative, radiation monitor RM 6038 detects radioactive leakage from reactor coolant pump thermal barrier and i
seal coolers, shutdown cooling heat exchangers, primary sample coolers, or the letdown system heat exchanger, which may enter the service water system through the intervening RBCCW system heat exchangers. Three, one-half inch sample lines which tap off the i
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discharges of three RBCCW pumps combine into a common inlet to the radiation monitor.
Each of the three lines contains a flow indicator, and an additional instrument indicates l
combined flow through the monitor. Monitor RM 6038 performs no automatic safety functions. Technical Specification (TS) 3.3.3.9, " Radioactive Liquid Effluent Monitoring Instruments," requires monitor RM 6038 to be in continuous operation at all times. If the l
monitor is inoperable for greater than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, service water system effluent must be
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sampled for gross radioactivity once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter. Calibration of the instrument is performed on a quarterly basis in accordance with instrumentation and controls (I&C)
Surveillance Procedure SP-2404AW, "RBCCW Liquid Radiation Monitor (RM 6038)
Calibration."
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Procedure SP-2404AW was performed on May 3, by two I&C technicians; one stationed in the control room, and the other at the monitor skid in the auxiliary building. The monitor
was logged out of service by control room operators, and the TS action statement was entered, at 7:57 a.m., on May 3. Service water effluent samples taken shortly thereafter indicated less than MDA. At the beginning of the surveillance, the I&C technician at the
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skid shut the radiation monitor sample canister inlet and outlet isolation valves. This was contrary to Step 4.7 of the procedure, which required the valves to be operated by Operations Department personnel. At the completion of the calibration, procedure Step 6.8.8, which requires Operations Department personnel to reopen the isolation valves, was missed. At 2:09 p.m., upon being notified by I&C that SP-2404AW was completed, control room operators logged monitor RM 6038 returned to service and logged out of the TS action statement. The shift operators' actions were not effective in verifying the correct return to service of this TS-required monitor.
During an interview with the inspector, the I&C technicians stated their belief that Operations had acquiesced in their manipulation of the valves by implication when permission to perform the procedure was obtained, and that traditionally the unlabeled valves had been under the operational control of the I&C Department. However, they also stated that they assumed that Operations personnel would restore the radiation monitor to service upon being notified that the calibration was complete. The inspector noted that Procedure SP-24CMAW did not require valve position or process flow restoration verification.
The inspector determined that the grab sample results (less than MDA) obtained on May 3 and May 6, provided reasonable assurance that no radioactivity had been released to the environment. However, the failure to identify and take the required compensatory actions of Technical Specification 3.3.3.9 was safety significant and is a violation of NRC requirements.
In addition, Administrative Control Procedure (ACP) QA-3.02E, " Procedure Compliance,"
which provides licensee management expectations regarding procedure adherence, states that the intent and direction of procedures shall be followed, and that deviation som procedures is j
not permitted without an approved change to the procedure. The inspector concluded that the j
TS violation was caused by the I&C technicians' failure to comply with the valve
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manipulation steps of Procedure SP-2404AW. The inspector identified as contributing causes the fact that the procedure contained no process flow restoration checks, and that the
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operators customarily assume that the monitor has to be returned to service based on notification from I&C that the surveillance has been completed. A conflict between the procedure requirements and traditional I&C Department practice regarding unlabeled instrument isolation valves also contributed to the incident.
Similar failures by I&C personnel to comply with procedure steps as written were documented by the NRC, in Inspection Reports 50-336/89-24, dated October 1989; 50-336/91-29, dated January 1992; and 50-336/93-06, dated April 1993. Licensee actions to prevent recurrence of these violations variously includul changes to affected procedures, counseling of personnel involved, and management presentations at department meetings emphasizing the importance of procedure compliance. In LER 50-336/93-09, the licensee stated as corrective action that the I&C technicians had been counseled regarding the importance of procedure compliance; that SP-21404AW was revised to clarify valve restoration instructions; and that verification and sign-off of normal process flow had been added to the procedure data sheet. In addition, the licensee committed to review and change other radiation monitor procedures. The inspector concluded that the proposed corrective actions were acceptable with the exception of the failure to address the ineffective operator actions to assure post-surveillance operability. This violation of licensee and NRC requirements could reasonably have been prevented by corrective actions for previous violations. Therefore, in accordance with the NRC enforcement policy of 10 CFR Part 2, Appendix C, the violation will be cited (50-336/93-11-004).
6.2 Containment Atmosphere Temporary Sample Rig Installation - Unit 2 On March 281993, at 8:45 a.m., a plant equipment operator (PEO) performing rounds in the
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auxiliary building found a temporary sample rig connected to containment atmosphere radiation monitor (RM-8123) and hydrogen monitoring system test fittings with isolation valves 2-AC-122 and 2-AC-124 open. Attached to the valves were danger tags requiring the valves to be shut. Operator logs indicated that the containment atmosphere had been sampled at 11:05 p.m., on March 27. Thus, the temporary rig had been unisolated from the containment atmosphere for approximately nine and one-half hours. The rig is used for remote sampling of the containment atmosphere prior to venting, purging, or routine
i containment entry, and is connected via plastic tubing to fittings located downstream of the isolation valves. The safety concern was the potential for release of radioactive material from the containment to the enclosure building should the pbstic tubing fail during post-accident operation of the hydrogen monitoring system. Since other isolation valves on the temporary rig were closed, the operability of radiation monitor RM-8123 was not affected. The PEO notified the control room of the condition, shut the isolation valves, and disconnected the rig.
The licensee initiated plant incident report (PIR) 2-93-57 to investigate the occurrence.
In the personnel questionnaire accompanying the PIR, the PEO who attached the danger tags stated that he did not first verify that valves 2-AC-122 and 2-AC-124 were shut, although he was aware of the requirement to do so. The PEO attributed the error to lack of attention to detail. Licensee Administrative Procedure ACP-QA-2.06A, " Station Tagging," Step 6.1.2.1, i
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requires valves to be ve-rified to be in the proper position when placing tags. The inspector concluded that the PEO's failure to verify that the isolation valves were shut prior to hanging the danger tags was a violation of procedure requirements. The PEO was counseled by operations supervision regarding attention to detail in the performance of equipment tagging.
In 1991, the NRC found that the licensee's administrative controls governing use of temporary rigs had been inadequate to assure that the design pressure boundary integrity of the radiation and hydrogen monitoring systems was maintained. Licensee corrective action consisted of procedure changes which assigned to the operations department the sole responsibility for installation / removal of the rig, and use of the station tagging system to prevent unauthorized operation of the isolation valves. The conective actions were found by
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the inspector to be acceptable in NRC Inspection Report 50-336/93-09.
Chemistry Procedure CP-2806X, " Containment Purge," and Operations Procedure OP-2383A, " Process Radiation Monitors Operation," assign the responsibility for comia; tion and disconnection of the rig and manipulation of the isolation valves to operations personnel.
In the PIR personnel questionnaires, three PEOs stated that chemistry technicians usually closed the isolation valves and disconnected the sample rig prior to calling operations to rehang the tags. The inspector confirmed this practice through interviews with several other operators. The inspector also found a general lack of familiarity with the responsibilities assigned to operators by Procedure OP-2383A, and was unable to etermine conclusively d
whether PEOs had consulted the procedure in the field prior to performing containment atmosphere sampling activities. The inspector discussed these findings with operations department supervision, who noted that PEOs had received no specific training on the procedure. The licensee committed to address these issues during operations shift briefings.
The inspector reviewed operations department memorandum MP-2-0-536, dated March 30,1993, and concluded that it correctly described operation's role in the containment sampling process. The shift briefings were completed on April 8,1993. In subsequent discussions with several operations shift crews, the inspector verified that the contents of the memorandum had been conveyed adequately.
The inspector also discussed containment sampling practices with the Unit 2 chemistry manager, who stated that the responsibility for manipulating valves was clearly demonstrated in chemistry procedures and that he expected that chemistry technicians were following the procedures. The manager further stated that he saw no need to question individual technicians regarding past practices, and that a note would be added to the daily chemistry status and shift turnover log reminding chemistry personnel to operate only those valves authorized by chemistry procedures. The inspector verified that this action was taken.
The inspector concluded that operations and chemistry personnel had not been familiar with the division of responsibilities regarding operation of the temporary sample rig, and that the common practices deviated from the requirements of the procedures. Step 6.2 of licensee Procedure ACP-QA-3.02E, " Procedure Compliance," requires that the intent and direction provided in procedures shall be followed during the course of activities, and that deviations
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from the guidance contained within the procedures are not permitted without an approved procedure change. The inspector found that manipulation of valves 2-AC-122 and 2-AC-124, and disconnection of the sample rig by chemistry personnel had been a common practice and was a violation oflicensee procedures. Regarding the recurring failure of system configuration controls for monitor RM 8123 and the temporary sample rig, the inspector
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concluded that licensee's causal analysis and corrective actions for previous failures, including actions to prevent recurrence, had not been implemented adequately. In addition, the inspector was concerned with the failure on multiple occasions of chemistry and operations
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personnel to follow procedures. Therefore, the violation of containment sampling procedures will be cited (50-336/93-11-005).
6.3 Corrective Actions For An Inoperable Effluent Radiation Monitor - Unit 2 On May 3,1993, reactor building closed cooling water (RBCCW) system radiation monitor RM-6038 was rendered inoperable due to failure to restore process flow to the monitor following performance of a surveillance procedure. The condition was identified and
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corrected by a plant equipment operator at 1:00 a.m., on May 6. NRC review of the conduct of the surveillance test is discussed in Section 6.1.2 of this inspection report.
The inspector performed an independent review of the incident to assess the scope and quality of the licensee's incident investigation and proposed corrective actions. The inspection consisted of system walkdowns, review of operating logs, records, and design documents, and personnel interviews. The inspector concluded that monitor RM-6038 had been inoperable (no flow) from 7:57 a.m., on May 3, to 1:00 a.m., on May 6,1993. Operators took no action on May 3 (at 2:09 p.m.), to verify the correct return to service of monitor RM-6038 prior to incorrectly declaring the monitor operable. In addition, the inspector reviewed OPS Form 2669A-2, " Unit 2 Auxiliary Building Logs," for plant equipment operator (PEO) rounds performed by three separate PEOs from May 3 to May 6,1993. The logs are required to be taken at least once per eight-hour shift, and include a checkoff
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verification that sample flow to monitor RM-6038 is between 10 and 20 gallons per minute (gpm). The log for May 3 correctly verified that monitor RM-6038 was off-line. In the logs for May 4 and May 5, there was a check mark in the applicable space for the midnight to 8:00 a.m., and the 8:00 a.m., to 4:00 p.m. shifts, indicating there was acceptable flow to monitor RM-6038, while the 4:00 p.m., to midnight entry is "OL" (off-line). The inspector observed that the licensee's incident investigation had been limited to the performance of Procedure SP-24NAW, and had not considered review of the PEO logs. The inspector requested that the licensee reconcile the apparent conflict between the actual status of the radiation monitor and the PEO log entries for those dates. The inspector also requested that j
the licensee address the apparent failure of operations shift supervision to note the apparent discrepancy during shift turnover log review and the failure to log into the applicable TS
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action statement as a result of the "off-line" log entries. NRC concerns regarding the scope
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of licensee incident investigations were documented previously in Inspection Report
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50-336/93-09. The Millstone 2 Unit Director stated to the inspector that licensee management shared this concern and that the process would be reviewed. These items are unresolved pending NRC review of the results of the licensee's investigations (50-336/93-11-006).
i During a walkdown of the radiation monitor system, the inspector found that scale markings on the 0 - 24 gpm sample line flow indicators FIS-6312, FIS-6313, and FIS-6314 included a J
' times 10' multiplication factor. The two on-line instruments thus indicated 1.5 gpm X 10
= 15 gpm each. This was consistent with nominal flow rate specified by auxiliary building i
rounds Form 2669A-2 and monthly operations surveillance Forms 2611C-2 and 2611D-2,
" Reactor Building Closed Cooling Water System Valve Alignment, Facility 1 and Facility 2,"
respectively. However, the actual sample line flow is about 1.5 gpm. The combined sample
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flow instrument (FIS-6038) mounted on the radiation monitor skid, indicated a flow rate of 2.0 gpm, the actual flow rate required by the radiation monitor. This instrument is not required to be checked during PEO rounds. The licensee stated that the individual sample line flow indicators had been instailed and calibrated to read 0 - 24 gpm (vice 0 - 240 gpm)
during plant construction in 1974 (multiplication factor removed), but that the scale markings had not been updated to reflect the change. In addition, no maintenance or calibrations of the instruments had been performed following initial installation. The !icensee removed the multiplication factor from the scales and committed to change the procedures by the end of June 1993. The acceptance criteriou on PEO rounds Form 2669A-2 was revised on June 14.
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However, valve alignment surveillance forms 2611C-2 and 2611D-2 were not changed prior to the regularly scheduled performance date, causing the PEO to interrupt the valve lineup to process a procedure change. The inspector considered that the licensee's failure to change the valve lineup forms in a timely fashion unnecessarily challenged the operator performing the surveillance and indicated weakness in timely followup of a nonconforming condition.
Regarding the accuracy and maintenance of the sample flow indicators, the inspector was concerned that this condition had existed without being questioned for almost 20 years, displaying lack of attention to detail and questioning attitude on the part of operators and I&C technicians. However, the inspector concluded that the operability of RM-6038 had not been adversely effected by the instrument scale discrepancies, and concluded that the licensee's corrective actions for this item were acceptable.
6.4 Secondary Containment Pressure Control-Unit 3 l
l On June 17, 1993, the licensee determined that the Millstone Unit 3 supplementary leak collection and release system (SLCRS) had not been demonstrated to be capable of maintaining the secondary containment at a subatmospheric pressure (-0.25 in. WG) at all elevations during worst case ambient conditions. A negative pressure condition is required to l
assure that post-accident radiation releases can be contained and filtered adequately prior to l
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During the development of a definitive solution to design deficiencies related to the auxiliary
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building filter system (ABFS) and the SLCRS (reference Inspection Report 50-423/92-23),
the licensee reviewed previously dispositioned SLCRS issues. A review and re-evaluation of NRC Information Notice (IN) No. 88-76, "Recent Discovery Of A Phenomenon Not Previously Considered In The Design Of Secondary Containment Pressure Control," revealed that the SLCRS operability could not be maintained throughout the winter months. System design had not taken into account temperature-induced differences in the absolute pressure gradients inside and outside of the containment enclosure building. Due to the higher density of cold outside air, outside pressure decreases more rapidly with increasing elevation than pressure inside the enclosure building, potentially resulting in a net positive pressure at the top of the containment.
i The licensee's initial response to IN No. 88-76, datec October 28,1991, stated that the containment enclosure building was not affected by the temperature induced pressure i
gradients because the enclosure building is a non-climate controlled uninsulated structure whose temperature closely follows the outside conditions at any given time. The differential temperature, and thus, pressure difference between the enclosure building and the outside environment would remain constant regardless of outside temperature or building elevation.
l However, actual temperature measurements taken in March 1993, yielded a temperature j
difference of 35 degrees Fahrenheit ( F). In response to the measured temperature difference, the licensee re-evaluated SLCRS operability.
i Based on available surveillance test data (-0.44 in. WG), current ambient conditions, Final Safety Analysis Report environmental data, and calculations to account for pressure / temperature differences across the containment enclosure at various elevations, the licensee concluded that the SLCRS is presently operable and will remain operable through at least October 31,1993. With the present SLCRS test results, maximum acceptable differential temperature to preclude exceeding the -0.25 in. WG at higher elevations is 40*F.
Worst case environmental data indicates that this 40 F limit can be exceeded during the winter. On June 17, upon completion of the reportability evaluation, the licensee reported the event in accordance with 10 CFR 50.72. The licensee stated that corrective actions will be implemented prior to October 31,1993.
The Millstone 3 accident analysis credits the maintenance of at least -0.25 in. WG pressure at all levels in the secondary containment structures to demonstrate accep' 31e off-site dose consequences. Since the unit operated with reactor coolant radioactivu) well below the technical specification limit, the effects of the condition on analyzed off-site exposures were minimized.
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The inspector concluded that the SLCRS surveillance is inadequate in that the negative pressure is not ensured at all elevations of the enclosure building and that Unit 3 may have operated in violation of the technical specification governing SLCRS operability. The inspector noted that the review of previously dispositioned SLCRS issues during the development of the final fix to the ABFS/SLCRS design basis issue demonstrates a strength
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l in the area of engineering and technical support. However, it now appears that not all of the ambient temperature considerations were properly considered and resolved durireg review of the ABFS temperature effects on the SLCRS. Also, the licensee's initial review of the concern documented in NRC Information Notice No. 88-76 was inadequate. Pending correction of the problem and addressal of the weakness in licensee review of industry
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operating experience, this issue remains unresolved (50-423/93-13-007).
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6.5 Review of Previously Identified Issues
I 6.5.1 Fuel Loading Error - Unit 1 L
Violation (50-245/91-12-01) was issued to document the incorrect placement of a fuel assembly into the core during refuel operations that were conducted during the 1991 outage period. The error occurred despite the fact that procedures called for independent verification of fuel handling activities and Unit 3 had a similar error during its prior refueling outage.
Upon identification of the error, all fuel movement activities were stopped. Previous fue!
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movement activities were verified to be correct through use of an underwater camera. The error was corrected and fuel transfer was resumed. No additional errors occurred during the remainder of the fuel movement activities. Also, this misplacement would have had minor l
safety significance since the assembly which was incorrectly placed had essentially the same fuel burnup as the other assembly. Licensee personnel believe that the incorrect fuel placement occurred when the fuel crane operators misread the fuel coordinate labeling or instructions.
Currently, fuel unloaded from the core is placed into the racks in a random pattern. During I
core reload, the random placement of fuel requires operators to go to various rack
coordinates. This discharge pattern increases the potential for incorrect fuel movement error, since operators then have to select the correct fuel assembly based upon correct reading of the
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fuel coordinates and follow through without following a set geometric pattern. To prevent i
recurrence of the event, the licensee intends to place the fuel assemblies which will be reused l
into the fuel racks in sequential order. Therefore, when core reload is occurring, licensee personnel will remove assemblies from each rack in sequence.
Another corrective action under consideration includes improving the identification of the fuel racks through the implementation of an enhanced marking scheme. In addition, measures to enhance the independent verification function are planned assure that both individuals are not subject to the same error. The licensee has committed to implement long term corrective
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actions prior to the commencement of the January 1994 refuel outage. This issue remains unresolved pending NRC review of the licensee's completed corrective actions.
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6.5.2 Equipment Anchor Bolt Inspections - Unit 1 Unresolved item (50-245/91-24-03) documented the discovery of corroded and failed anchor bolts on safety-related air handling systems at Unit 1. Other degraded bolts were also noted in the torus area during a subsequent NRC walkdown as documented in NRC inspection
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report (50-245/92-24). The inspector noted that the licensee had no program to assure the
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integrity of safety-related anchorages that were subject to degradation. This item was opened
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to track the development of a licensee inspection plan for safety-related anchor bolts at Unit 1.
In response to the above findings, the licensee developed a program to periodically inspect anchor bolts for excessive corrosion during extended outage periods. This program was formalized in departmental instruction 1-ENG-3.02, " Implementation of the Unit 1 Anchor Bolt Inspection Program." The instruction provides selection criteria, process controls, and mechanisms for data collection and review. The inspector reviewed the instruction and found it to be fully responsive to the safety concern. Prior to startup from the March 1992 maintenance outage, sixteen component baseplates were selected for inspection. No corrosion was detected. Therefore, anchor bolt degradation does not appear to be a significant concern at this time. This item is closed.
6.5.3 ESAS Undervoltage Protection Channel Surveillance - Unit 2 i
This item (Unresolved 50-336/93-09-02) involved problems identified by the licensee during
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a monthly surveillance test of the engineered safety features actuation system (ESAS)
undervoltage protection channels. All of the system bistable setpoints were found to exceed the acceptance criteria of the procedure by the same magnitude and direction, and were readjusted as each out-of-specification condition was identified. Subsequently, the licensee determined that the test circuit of the bistable modules had been modified by a system upgrade during the 1992 refueling outage. The change made one of the test instruments specified by the surveillance procedure incompatible with the bistable modules due to low input impedance. The incompatibility of the specified test equipment with the test circuit change had not been identified during the licensee's design change and procedure reviews.
In its plant incident report (PIR), the licensee identified " procedure deficiency" as the cause
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of the problem. The inspector found that the licensee had been aware of the test circuit change, but had not included this fact in its root cause evaluation of the incident. Thus, the licensee did not address the apparent design change and procedure review program weakness in its corrective actions. In response to the inspector's questions, the licensee has recommended changes to the design change and procedure review procedures to include evaluation of plant electrical modifications for maintenance and test equipment suitability.
The licensee also committed to assess the scope of PIR root cause evaluations as part ofits corrective actio.-
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After finding the first ESAS channel out of specification, the instrumentation and controls (I&C) technician stopped work, consulted his supervisor and the operations shift supervisor,
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and verified the calibration of the test equipment. Finding no discrepancies, he continued the surveillance test, readjusting discrepant setpoints on six bistables for the remaining protection
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channels. At the inspector's request, the licensee evaluated this practice, concluded that the I&C personnel had acted in accordance with procedures, and determined that no further corrective action was required. The inspector found this response to be unacceptable. The
inspector considered that after the same problem occurred on multiple protection channels, and the cause of the discrepancy had not been identified, the potential existed that readjustment of the remaining channels could render the entire undervoltage protection function inoperable. The inspector concluded that prior to continuing with the surveillance, j
I&C engineering should have been consulted, and the cause of the discrepant setpoints
I identified. The inspector discussed this issue with the unit director, who agreed that more timely engineering involvement was desirable, and committed to address this conclusion with j
unit department managers. This item remains unresolved pending implementation of the
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licensee's proposed corrective actions.
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l 6.5.4 Failure to Follow Procedure - Unit 3 This item (Violation 50-423/91-04-01) involved the failure of operators to adequately follow the loop fill procedure which resulted in the overpressurization of 'B' reactor coolant system j
(RCS) loop piping. The inspector determined the cause of the incident to be the lack of verification of the position of the RCS reliefline isolation valve and inadequate communications between the shift outage crew and the control room staff. Licensee action to
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l prevent recurrence consisted of adding a procedure step to place the relief valve in service,
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vice relying on a system valve lineup. Also, the loop fill procedure was converted from a system operating procedure to a general operating procedure. System operating procedures
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provide detailed instructions normally involving a single system, whereas general operating
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I procedures provide direction for evolutions involving multiple systems. Additionally, general operating procedures require the initialing of completed steps, which addresses the lapse in l
communication which contributed to the event. The inspector verified that the general l
operating procedure for loop fill had been issued and concluded that the licensee's corrective l
actions had addressed the cause of the violation effectively. This item is closed.
6.5.5 Inadequate In-service Inspection examinations - Unit 3 This item (Violation 50-423/91-05-01) involved the failure to report and evaluate liquid
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penetrant indications in accordance with Section XI of the ASME Boiler & Pressure Vessel Code. The licensee indicated that contracted inspectors were responsible for the missed indications. All examinations performed by the individuals in question were reperformed.
Additional non-reported indications were identified and evaluated by the licensee and determined to be acceptable. All but one of the non-reported indications had been performed i
by a newly qualified Level II inspector. The Ibensee attributed the error to a weakness in the contractor training and testing process.
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To prevent recurrence, the licensee revised the liquid penetrant and magnetic particle examination procedures to clearly define relevant indication recording and evaluation criteria.
In addition, Procedure QCTS-2.17, "NDE Contractor Training and Monitoring," was modified to require each contractor to attend and pass training in each NDE method, including specific procedure training and demonstration. If any contractor fails to pass the general, specific, or practical examination given by the licensee at the site, they will not be able to perform that NDE method during that outage without passing a retest. The inspector concluded that the licensee's corrective actions were adequate. This item is closed.
6.5.6 Overlap Testing Deficiencies - Unit 3 l
This item (50-423/93-07-06) involved the failure to adequately test entire instrument channels from the detector to actuating device in accordance with technical specifications (TS). In i
response to this deficiency the licensee established a task force to perform a review of overlap testing issues associated with the reactor trip system and the engineered safety features actuation system (ESFAS) instrumentation and interlocks. The purpose of the task force is to ensure that the surveillance procedures verify that overall system functional capability is maintained. To date, the overlap task force has identified incomplete surveillance procedures i
for testing the cold overpressure protection system (COPS); main steam isolation valves l
(MSIVs); and load shedding of the charging pumps, the 'C' service water pump, and the 'C'
reactor plant component cooling water (RPCCW) pump. However, no actual equipment problems were identified. The licensee reported the events in accordance with 10 CFR 50.73(a)(2)(i) as conditions prohibited by TS.
l On May 20,1993, the COPS was declared inoperable due to inadequate surveillance testing.
l The TS surveillance (4.4.9.3.1.a) required that an analog channel operational test on the
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power operated relief valve (PORV) actuation channel, excluding valve operation, be performed within 31 days prior to entering a condition in which the PORV is required and at
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l least every 31 days thereafter when the PORV is required to be operable. However, per j
Surveillance Procedure (SP) 3442J11/12, " Train A/B Solid State Protection System Operational Test," only the portion of the circuit from the sensor to the input relays of the solid state protection system (SSPS) were being tested at this frequency. The operational test of the SSPS, which consists of actuation logic tests and master relay tests, is performed on a 62 day schedule. Slave relay tests, which cover slave relays and the portion of the circuitry j
up to the actuation device, are performed quarterly.
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On May 28, the overlap task force determined that a portion of the main steam line isolation (MSI) engineered safety features signal to the MSIVs had never been tested. The MSI was declared inoperable. The portion of the circuit not tested was an interposing relay and its contacts. This interposing relay de-energizes when its slave relay actuates on a MSI signal.
This causes the MSIVs to rapidly close. The interposing relay is required to be tested on a i
refueling frequency in accordance with TS.
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On June 1, the overlap task force discovered that the loading shedding features of the 'C'
RPCCW pump, 'C' service water pump, and the charging pumps were not properly tested.
The 'C' RPCCW pump (a swing pump which can be tested from either bus), and the 'C'
service water pump (one of two "A" train pumps), load shedding function were not tested for the loss of power (LOP) and the LOP with an engineered safety features actuation signal during the last 18 month surveillance. The surveillance procedures which test this function lacked specific guidance to ensure that all combinations of RPCCW and SW pumps were tested. As a result, the 'C' RPCCW pump and 'C' service water pump were tagged out-of-service to prevent potential overload of the emergency diesel generators (EDGs) until these features could be tested. In addition, the diesel load shedding function for the charging pumps had not been verified in the post loss of coolant accident recirculation mode. Because the charging pumps could not be taken out of service, both emergency diesel generators were declared inoperable due to potential overloading.
t In each of these cases, components were immediately declared inoperable, the applicable TS action statements were entered, and all of the components, with the exception of the load shedding function for the 'C' RPCCW pump on the 'A' train, were tested satisfactorily. The
'C' RPCCW pump is scheduled to be tested in the future, and prior to declaring it operable for 'A' train use. The licensee has generated internal commitments to change the surveillance procedures for these components to er sure that they will be adequately tested in the future.
The licensee determined that the root cause of these events wrs management deficiency in that a comprehensive approach to testing was not implemented effectively during procedure development at plant startup. To prevent recurrence, the licensee stated that the overlap task force will continue to review procedures associated with reactor trip and ESF systems to determine if any similar conditions exist, and will make recommendations for implementing a comprehensive test program.
The safety significance of these events was small since all of the components tested satisfactorily and similar circuitry used throughout the plant have no record of failures. The inspector noted that prior to the development of the task force, corrective actions for surveillance test procedure deficiencies were narrowly focused and addressed only individual events. The development of the task force was an appropriate response to the recurrence of overlap testing problems. This item remains unresolved pending the completion of the overlap task force review, and NRC review of licensee corrective actions.
6.5.7 Diesel Generator Fuel Oil Storage Capacity - Unit 3 Unresolved item 50-423/93-07-06, documented the licensee's commitment to conduct a 10 CFR 50.59 evaluation of the current diesel generator fuel oil storage capacity against the plant design basis as specified in the final safety analysis report (FSAR) and the NRC safety evaluation report (SER) for Unit 3. On March 31, 1993, the licensee submitted its 50.59 evaluation to NRC which concluded that although Unit 3 does not have the fuel oil capacity detailed in the Unit 3 FSAR and SER, the current capacity is acceptable primarily due to the
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stated ability to obtain additional fuel delivery within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee also concluded that the deficit in fuel capacity derived primarily from more accurate and/or conservative calculational methodology did not constitute an unreviewed safety question.
NRC reviewed the licensee's March 31,1993, submittal and provided a formal response letter dated June 7,1993. NRC determined that the referenced design parameters for diesel fuel oil storage capacity constituted, in part, the design basis for Unit 3 and therefore the failure to meet these criteria represented an unreviewed safety question because the margin of safety had been reduced. The licensee was directed to submit a license amendment for NRC review and approval.
The inspector reviewed the licensee's activities regarding this concern and confirmed that Unit 3 has maintained the technical specification required volume of on-site fuel storage.
Also, the licensee brought more fuel oil on site in temporary storage to provide additional onsite capacity (diesel endurance) until this issue is resolved. The inspector verified that the temporary storage was properly evaluated and acceptable with regard to the fire hazards analysis.
The inspector was concerned that the licensee's evaluation of the Unit 3 fuel oil capacity issue did not recognize that the plant design basis was not met and that failure to meet this design basis represents an unreviewed safety question. The licensee reported to NRC in accordance with 10 CFR 50.72 the plant's operation outside the design basis on June 11,1993. This issue remains unresolved pending NRC action on the licensee's license amendment and inspector followup of the licensee's safety evaluation process.
7.0 MANAGEMENT MEETINGS Periodic meetings were held with various managers to discuss the inspection findir..s during the inspection period. Following the inspection, an exit meeting was held on July 16, 1993, to discuss the inspection findings and observations with station management. Licensee comments concerning the issues in this report were documented in the applicable report section. No proprietary information was covered within the scope of the inspection. No written material regarding the inspection findings was given to the licensee during the inspection.