IR 05000313/1998004
| ML20248J581 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 06/04/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20248J529 | List: |
| References | |
| 50-313-98-04, 50-313-98-4, 50-368-98-04, 50-368-98-4, NUDOCS 9806090198 | |
| Download: ML20248J581 (28) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-313; 50-368 License Nos.:
50-313/98-04;50-368/98-04 Licensee:
Entergy Operations, Inc.
Facility:
Arkansas Nuclear One, Units 1 and 2 Location:
1448 S. R. 333 Russellville, Arkansas 72801
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Dates:
March 29 through May 9,1998 Inspectors:
K. Kennedy, Senior Resident inspector S. Burton, Resident inspector l
J. Melfi, Resident inspector Approved by:
Elmo E. Collins, Chief, Project Branch C
Division of Reactor Projects ATTACHMENT:
SupplementalInformation 9906090198 990604 PDR ADOCK 05000313 G
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EXECUTIVE SUMMARY Arkansas Nuclear One, Units 1 and 2 NRC Inspection Report 50-313/98-04;50-368/98-04 This routine announced inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.
Ooerations Unit 1 operators performed well during drain down of the reactor coolant system to a
reduced inventory. Operators monitored reactor coolant system (RCS) levels and maintained good communications during the evolution (Section 01.2).
Unit 1 operators responded quickly and appropriately to the sudden failure of a
temporary flexible steam pipe installed to conduct emergency feedwater (EFW) pump turbine overspeed testing (Section 01.3).
Unit 1 control rods functioned as expected while latching, withdrawing, and during the
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performance of rod drop testing. Previous problems with sticking of control rods during rod movement were not experienced during this testing. Operators conducted the testing
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well and in accordance with procedures (Section 01.4).
Unit 1 operators performed well during the evolution to bring the Unit 1 reactor critical.
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The approach to criticality was deliberate and well controlled (Section O'. 5).
The licensee's walkdown and cleanup of the Unit 1 reactor building was effective in
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preparing Unit 1 for power operation (Section 02.1).
Unit 1 operators authorized the temporary release of a hold card on a motor-operated
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valve circuit breaker without obtaining the authorization of two lead craftsmen signed in on the hold card. The circuit breaker was subsequently closed and the valve was stroked. Although no personnel were injured, this error created the potential for a personnel injury or fatality. This was determined to be a violation. Although the licensee had implemented a number of corrective actions following a similar near miss event in January 1997, recurring errors in the implementation of the hold card process indicated
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that these corrective actions have not been effective in preventing recurrence of hold l
card errors.
Maintenance The licensee successfully completed a major modification to replace the Unit 1 reactor
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building purge valves. Problems encountered during installation and postmodification testing were appropriately resolved. The inspectors noted good management and quality control oversight of the activity (Section M1.2).
Modifications to Unit 1 reactor building spray system motor-operated valves were
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completed by knowledgeable technicians in accordance with approved procedures.
Technicians demonstrated a good questioning attitude when unexpected water was
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encountered during valve disassembly and when a procedural clarificanon was required for drilling a hole to accommodate a disc retaining dowel pin (Section M1.3).
Engineenng An inspection of Unit 1 high pressure injection (HPI) nozzles revealed that the nozzles
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were intact and free from breakage or cracking. Inspection results were properly recorded and dispositioned (Section E1,1).
Modifications to Unit 1 decay heat removal system isolation valves to prevent pressure
' locking between them were installed as designed (Section E1.2).
The licensee effectively demonstrated that the Unit 1 penetration room ventilation system
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remained operable with damper seals deflated and supported their justification for not replacing the seals every 5 years (Section E1.3).
The licensee conducted a comprehensive review of the Unit 1 stuck control rod issue
and developed a good action plan to identify the cause of the sticking. The licensee concluded that the previous problems associated with control rod sticking were the. result of binding in the control rod drive mechanisms (CRDMs). Although inspection of the
CRDM intemals for the two stuck rods did not reveal a conclusive root cause, the licensee determined that the probable cause was the presence of debris in the CRDM (Section E8.1).
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The licensee resolved an NRC identified discrepancy with a conversion factor used to i
correlate the level of water in the Unit 1 reactor building sump to the volume of water in the sump. A procedure change was required to correct the nonconservative value in the procedure (Section E8.2).
Unit i experienced a 36 percent failure rate when 53 of 149 safety-related 120 Vac
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molded case circuit breakers failed overcurrent trip testing. Similar testing of ten 480 Vac safety-related molded case circuit breakers yielded no failures (Section E8.3).
Piant Sunoort L
Unit i health physics technicians took appropriate actions in response to an individual c
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with facial and intemal contamination (Section R1.2).
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6-The licensee conducted appropriate inspections in response to a potential tampering
event associated with foreign material found in bearings on the Unit 1 main turbine generator (Section S1.1).
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floport Details Summary of Plant Status LlDd 1 At the beginning of the inspection period, Unit 1 was shut down for Refueling Outage 1R14.
Following completion of outage activities, the reactor was restarted on May 9 and the plant was in hot standby with reactor power less than 2 percent at the end of the inspection period.
Und 2 Unit 2 began the inspection period at 100 percent power. On March 30 power was reduced to 70 percent to repair a leaking condenser waterbox manway. Power was returned to 100 percent on March 31. On May 8 power was reduced to 70 percent to repair a main condenser tube leak.
Following completion of the repairs, power was retumed to 100 percent on May 10 and remained there for the duration of the inspection period.
l. Operations
Conduct of Operations 01.1 General Comments (71707)
The inspectors observed various aspects of plant operations, including compliance with Technical Specifications (TSs); conformance with plant procedures and the Safety Analysis Report (SAR); shift manning; communications; management oversight; proper system configuration and configuration control; housekeeping; and operator performance during routine plant operations, the conduct of surveillance, and plant power changes.
During tours of the plant, including the Unit i reactor building, the inspectors found that housekeeping was generally good and discrepancies were promptly corrected. A decline in housekeeping was noted during the conduct of the Unit 1 outage. By the end p
of the inspection period, which also corresponded to the end of the Unit 1 outage, i
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licensee management placed significant emphasis on improving plant housekeeping.
The conduct of operations was professional and safety conscious. Evolutions such as surveillance and plant power changes were well controlled, deliberate, and performed according to procedures. Shift turnover briefs were comprehensive. Housekeeping was
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generally good and discrepancies were promptly corrected. Safety systems were found
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to be properly aligned. Specific events and noteworthy observations are detailed below.
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01.2 - Unit 1 - Drain to Midloop a.
Insoection Scooe (71707)
During the Unit 1 refueling outage, the inspectors observed operators drain the RCS to reduced inventory on April 1 and 25.
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Observations and Findinas inspectors monitored two separate RCS drain downs to reduced inventory for the installation and removal of steam generator nozzle dams. These evolutions were carefully controlled by the control room supervisor (CRS) and shift supervisor. Both ensured that no evolutions or testing were conducted that would distract the operators i
involved. The CRS made use of extra onshift personnel to control evolutions that were not part of the drain down evolution.
During the first draindown, the licensee conducted an exercise to test the ability of the personnel in the reactor building to rapidly close the equipment hatch in the event such measures had to be taken. This test was conducted satisfactorily and did not interfere with the drain down.
The licensee used Procedures 1103.011, Revision 24, " Draining and N Blanketing of the
RCS," and 1015.002, Revision 20. " Decay Heat Removal and LTOP System Control," to control this evolution. The licensee appropriately evaluated the risk associated with draining the RCS to reduced inventory. Two trains of decay heat removal, emergency backup power, and makeup water sources were available during the drain downs and
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operation in reduced inventory. The licensee monitored the RCS level using two independent trains of instrumentation and a tygon tube. Operators monitored core exit temperatures and decay heat removal system temperatures during this evolution.
Prior to the start of the drain down, inspectors verified that instruments providing RCS
!evel indication were properly aligned. The initial conditions and valve lineup were verified and performed using the wrong section of Procedure 1103.011. This error was caught by the shift supervisor and the prerequisites were reverified using the proper section of the procedure before the actual drain down had begun. Secondly, the procedure contained steps which improperly directed operators to close cold leg drain valves prior to draining the steam generator lower heads. This procedure error was recognized by an auxiliary operator performing the valve lineup in the reactor building.
The incorrect procedure steps were modified using the approved procedure change process and the evalution was completed without further problems.
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Conclusions
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Unit 1 operators performed well during draindown of the RCS to reduced inventory.
l Operators monitored RCS levels and maintained good communications during the evolution.
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01.3 UniU_- Failed Temocrary Steam Line a.
Insoection Scooe (71707. 93702)
During the performance of an overspeed test on the EFW Pump Turbine K-3, a temporary steam admission line failed. The inspectors observed operator actions during
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the failure and reviewed the causes of the event.
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Observations and Findinas On April 24, the licensee performed Procedure 1106.006, Revision 58, " Emergency Feedwater Pump Operation," Supplement 5, "EFWP Turbine Overspeed Trip Test." To perform this test, a temporary, flexible steam hose was connected to supply steam from the startup boiler to the EFW steam supply line. This flanged, flexible hose was 5 feet long,4 inches in diameter, and made of a thin (0.020 inch) metal bellows surrounded by a flexible wire braid. After the piping was warmed by the startup boiler steam supply, an operator began throttling open a remote valve to supply full steam pressure to the system. At approximately 200 psi steam pressure, the flexible steam hose failed and steam entered the roorn. The personnel in the room left immediately. Two individuals received minor injuries in exiting the room.
The inspectors were in the control room at the time of the event and observed the response of control room operators. The CRS and operators dealt quickly with this event, isolating the line, and dispatching a medical response team.
The inspectors toured the GFW pump room with licensee personnel and observed that the flexible wire braid and the bellows were torn off one of the hose flanges. The flexible wire braid is designed to act as an axial restraint and vibration dampener. The bellows provides the pressure boundary. Further licensee examination of the flexible hose revealed that the wire braid did not appear to be properly welded to one of the flanges.
Failure of the wire braid would reduce the hose's axial support and allow the thin bellows piping to rapidly expand. The licensee believed that the failure of flexible hose was due to a manufacturing defect.
The hose was purchased by the licensee as a nonquality-related temporary testing connection. The size, length, and end connections of the flange were specified in the procurement documents but no standards were referenced. The startup boiler system and the EFW system steam pipe was built to ANSI B31.1, * Power Piping."
Sect;on 102.2.2 of ANSI B31.1 allows the use of a temporary hose provided its pressure
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and temperature ratings are not exceeded. The supplier of the flexible pipe informed the l
licensee that all hoses were tested to higher pressures than those expected during specified applications. The licensee initiated Condition Report (CR) 1-1998-0416 in response to this event and, at the conclusion of the inspection, was evaluating the root cause for this failure.
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Conclusions Unit 1 operators responded quickly and appropriately to the sudden failure of a temporary flexible steam pipe installed to conduct EFW pump turbine overspeed testing.
01.4 Unit 1 Rod Droo Testina a.
Insoection Scooe (71707)
On May 8, the inspectors observed Unit 1 control room operators perform rod drop testing in accordance with Procedure 1304.035, Revision 15, " Unit 1 Position Indicator Panel Alignment and Rod Drop Test." This testing, which is performed every 18 months as required by TSs, measures the time that each rod takes to travel from the fully withdrawn position to the 3/4-insertion point upon tripping.
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Observations and Findinca Safety Group 1 rods had already been withdrawn prior to the start of the testing. The inspectors observed the prebrief conducted in the control room and found it to be thorough. Operators verified that all of the groups were latched in accordance with Procedure 1105.009, Revision 15,"CRD System Operating Procedure." The inspectors observed that, during the latch orification and withdrawal of Groups 2-7 to the 100 percent withdrawn position, all rods moved freely. Although the shutdown margin was sufficient to maintain the reactor subcritical during the testing, operators closely monitored source range nuclear instrumentation as the rods were withdrawn. Position indications were closely monitored for each rod and necessary adjustments were made by instrumentation and control technicians. With Groups 1-7 rods fully withdrawn and Group 8 rods withdrawn approximately 5 percent, operators initiated a reactor trip. All i
rods in Groups 1-7 fully inserted within the required time, and Group 8 rods did not insert as designed.
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Conclusions Unit 1 control rods functioned as expected while latching, withdrawing, and during the performance of rod drop testing. Previous problems with sticking of control rods during rod movement were not experienced during this testing. Operatcrs conducted the testing well and in accordance with procedures.
01.5 Unit 1 - Reactor Startuo a.
Insoection Scoce (71707)
On May 9, the inspectors observed Unit 1 operators bring the reactor critical following tha completion of maintenance activities associated with Refueling Outage 1R14.
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Qhservations and Findinos
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- Operators performed the' reactor startup in accordance with Procedure 1102.008, Revision 16, " Approach to Criticality." The approach to criticality was well controlled and
. deliberate. The inspectors observed very good control and oversight of the startup by the -
CRS and shift superintendent. Operators remained focused on the startup at all times, a -
professional atmosphere was maintained in the control room, and personnel access to the control room was strictly controlled. Operators demonstrated very good self-I checking and peer-checking techniques and communications were effective. During the approach to criticality, the reactor operator and CRS were not assigned any other duties.
Operators stopped rod withdrawal whenever an alarm was received in the control room to address the alarm condition.
The first crew that the inspectors observed commenced the startup and withdrew rods in the safety groups prior to a crew tumover. Procedure 1102.006 stated that operators shall not conduct shift relief until the reactor is critical at greater than or equal to 1 percent power or shutdown by 1.5 percent delta k/k. Prior to conducting crew tumover, I
operators verified that the reactor was shut down by the mquired amount. Following crew tumover, the nev' crew recalculated the estimated critical position, as required by the procedure, and began withdrawing rods in the regulating group. The rod withdrawal was performed by a trainee under the direction of a licensed reactor operator. The inspectors observed appropriate oversight of the trainee.
During the withdrawal of Group 7 rods, reactor engineers present in the control room determined that reactor criticality would not be achieved by the time all rods were withdrawn. As required by Procedure 1102.008, operators consulted with reactor engineers and utilized Procedure 1302.020, Revision 6, " Reload Criticality and Low Power Physics Test," to continue the approach to criticality. Operators and reactor engineers determined the amount of dilution that would be required to achieve criticality and added the appropriate amount of makeup water to the RCS. Criticality was achieved at 10:42 a.m. on May 9.
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Conclusions Unit 1 operators performed well during the evolution to bring the Unit i reactor critical.
The approach to criticality was deliberate and well controlled.
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Operational Status of Facilities and Equipment O2.1 Unit 1 - Reactor Buildina Walkdown a.
. lascection Scooe (71707)
. The inspectors toured the Unit 1 reactor building on May 7 during heatup of the RCS l
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following completion of maintenance activities performed during Refueling Outage 1R14.
This tour was conducted following the licensee's preheatup walkdown of the buiUing but
, prior to their precriticality walkdown.
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Observations and Findinos The inspectors toured the Unit i reactor building following completion of maintenance activities performed curing Refueling Outage 1R14 and fnund that, with only minor exceptions, the building was free of loose materials. The eueptions were corrected by
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the licensee. The sump screens were intact and no gaps were identified. The inspectors walked down portions of the reactor coolant pump lubricating oil collection system and found it to be properly configured, c.
Conclusions The licensee's walkdown and cleanup of the Unit i reactor building was effective in
preparing Unit 1 for power operation.
Operator Knowledge and Performance 04.1 Unit 1 - Imoroner Clearance of Hold Card a.
Insoection Scooe (71707)
On March 31, the licensee discovered that Unit 1 operations personnel had authorized the removal of a hold card associated with a circulating water pump discharge valve, energized the valve's motor operator, and stroked the valve without obtaining the authorization of craftsmen who were signed in on the hold card. This error created the l
potential for a serious personnel injury. The inspectors reviewed the circumstances surrounding this event, CRs related to previous hold card errors, cnd the licer see's corrective actions for past hold card errors.
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Observations and Findinos
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On March 31, maintenance personnel requested that hold cards associated with Valves CV-3617, -3621, -3625, and -3629 be temporarily removed so that the valves
could be stroked open to perform maintenance. These valves are the discharge valves for each of the four circulating water pumps. The breakers for each of the motor-operated valves had previously been hold carded in the open position using separate Hold Card Authorization Forms, Hold Card Serial Numbers 98-1-0361, -0362, -0363, and -0364, respectively.
Form 1000.027C, " Partial / Temporary Release Authorization Sheet," was completed for each of the valves by two licensed senior reactor operators working in the outage control center. Procedure 1000.027, Revision 24, " Hold and Caution Card Control," required an l
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operator to verify that all craftsmen signed in on the hold card were listed on Form 1000.027C and that each lead craftsman reviewed and signed the form, thus
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documenting release authorization for all lead craftsmen signed in on the tagout.
l Procedure 1000.027 also required a CRS to review the completed Form 1000.027C and l
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verify that all craftsmen signed in on the hold card were lirted on the form and that release authorization had been obtained from alllead craftsmen. These requirements were also clearly stated on Form 1000.027C.
In completing Form 1000.027C for the temporary release of the hold card on Valve CV-3629,. the first operator failed to identify that two individuals had signed in on Hold Card 98-1-0364 associated with Valve CV-3629.' As a result, the operator did not list the craftsmen on Form 1000.027C and did not obtain their signatures authorizing release of the hold card. The operator signed the form, indicating that the required.
. reviews had been completed. The second licensed senior reactor operator was required to perform the name verification that the first operator had performed but also failed to identify that the two individuals were signed in on the hold card and signed Form 1000.027C approving the temporary release. The inspectors noted that craftsmen were signed in on only one of four packages, the package for Valve CV-3629.
Once the temporary release of the liold cards was authorized, a third operator was directed to clear the hold cards, close the breakers, open the valves, then open the breakers, and rehang the hold card tags. As a result of previous hold card errors, Unit 1 operations management had established a management expectation that operators removing hold cards would verify that all required signatures were obtained on Form 1000.027C. This third operator also failed to identify that craftsman were signed in on the hold card. The third operator and another operator proceeded to the motor-control center to remove the hold cards and stroke the valves. Upon opening the second valve, Valve CV-3629, the operators identified that two individuals had signed in on the hold card authorization sheet for that valve and had not authorized the terrporary
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release of the hold card. The operator immediately notified the outage control center and checked to ensure that no personnel were working in the area of the valve. At the time Valve CV-3629 was stroked, electricians were walking down the area in preparation for removal of the valve operator. They were awaiting a safety check of the confined space where the valve was located when they observed that the valve had stroked.
In response to this event, the licensee immediately established an event investigation team to perform a prompt root cause investigation and develop corrective actions. The licensee's short-term actions to prevent recurrence included:
The temporary re!uase of hold cards was prohibited for the remainder of the
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refueling outage unless authorized by the Unit 1 operations manager.
I The use of personal identification tags and/or locks on all hold-carded
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components was required if improper operation of the component could cause immediate personalinjury.
Electrical components being returned to service from maintenance or modification
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activities were required to be walked down by operations personnel prior to either temporary or permanent clearance of hold cards and re-energization.
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steps in the hold card process and make the expectations more consistent for temporary and permanent clearance of hold cards.
At the end of the inspection period, the licensee had not yet completed their formal root cause evaluation associated with CR 1-98-0209 written to document this event. The licensee plans to finalize long-term corrective actions as part of this process.
l The inspectors determined that the failure of the two SROs to have each lead craftsman review and sign the temporary release authorization sheet, Form 1000.027C, as required by Procedure 1000.027, Revision 24, " Hold and Caution Card Control," was a violation of Unit 1 Technical Specification 6.8.1 (50-313/9804-01).
. NRC Inspection Report 50-313/96-09; 50-368/96-09 documented a hold card error which occurred in January 1997 in which a Unit 1 CRS failed to verify that electricians had l
completed work and authorized clearance of a hold card and closure of a breaker while work on a 480 voit breaker was in progress. This resulted in a Notice of Violation. The inspection report documented the inspectors' review of CRs for the previous 2 years and identified that those CRs classified as significant fell into three categories: (1) personnel failing to verify the adequacy of hold cards prior to commencing work; (2) inadequate hold card boundaries for work activities; and (3) failure to properly position components when establishing hold card bot.ndaries. On July 31,1997, the licensee initiated CR C-1997-0246 to document the identification of a potential adverse trend due to continuing problems with implementation of the hold card process. CR C-1997-0246 listed eight CRs that had been initiated in the first two quarters of 1997 as a result of hold card errors. The root cause analysis report for this CR provided a summary of the 21 CRs related to hold card errors that occurred during the period from January 1996 to August 1997 and determined that 70 percent of the hold card errors were due to personnel error and 18 percent were due to a lack of clear management expectations.
The root cause for the adverse trend identified in CR C-1997-0246 was determined to be station management failure to identify, implement, communicate, or enforce the necessary controls or accountabilities required to maintain or improve performance in the implementation of the hold card process. The result of this CR was the development of a number of corrective actions to p. event recurrence of the hold card errors.
During this inspection period, the inspectors reviewed 13 cps written since December 1997 which documented errors made in implementation of the hold card and caution card process, including the CR associated with the Jnit 1 circulating water pump discharge valves. Nine of these errors occurred during the Unit 1 Refueling
. Outage 1R14. The CRs were written to document the following errors: (1) removal of a
' tagged component; (2) inadequate hold card instructions; (3) tagged components that were found in the wrong position; (4) inadequate hold card boundaries; (5) failure to follow the instructions of a caution card; (6) operation of tagged components;
' (7) performance of work on.a system that was not tagged out; (8) and failure to sign in on a hold card prior to commencing work. ~ One of the findings of the event investigation team, which was established to review this recent near miss event, was that, based on
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the recurring and similar hold card errors that have occurred, past corrective actions have not been adequate or effectively implemented. Based on the review of hold card errors made in the last 6 months, the inspectors agreed with the team's assessment and concluded that the licensee's previous corrective actions have not been successful in ensuring the proper implementation of their hold card process, c.
Conclusions Unit 1. operators authorized the temporary release of a hold card on a motor-operated valve circuit breaker without obtaining the authorization of two lead craftsmen signed in on the hold card. The circuit breaker was subsequently closed and the valve we stroked. Although no personnel were injured, this error created the potential for a personnel. injury or fatality. This was determined to be a violation. Although the licensee had implemented a number of corrective actions following a similar near miss event in January 1997, recurring errors in the implementation of the hold card process indicated that these corrective actions have not been effective in preventing recurrence of hold card errors, 11. Maintenance M1 Conduct of Maisitonance M1.1 GeneralComments a.
Inspection Scope (62707)
The inspectors observed all or portions of the following maintenance activities:
Unit 1 - Job Order 00971885, " Cleaning of Diesel Fuel Oil Storage Tank T57A,"
on April 13.
Unit 1 - Design Change Package (DCP) 951014D102, " Solenoid Valve Mod,
' Reactor Vessel High Point Vent Valves," between April 2 and 21.
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Unit 1 - Controlled Work Package 977863 to repair Fire Penetration
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Seal 149-0055 observed on April 22.
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Observations and Findings The inspectors found the work performed in these activities to be professional and thorough. Work was performed according to procedures and the workers were knowledgeable of their assigned tasks. Maintenance supervisory involvement was
. observed on these activities and appropriate foreign material exclusion controls were implemented. Infrequently performed tests or evolution briefs were held when required.
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M1.2 Unit 1 - Observation of Purae Valve Modification a.
Insoection Scooe (62707)
During the Unit i refueling outage, the inspectors observed portions of the modification to the reactor bui! ding purge valves. This modification replaced the four 54-inch diameter valves with 24-inch diameter valves,
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Observations and Findinas The licensee installed this modification using DCP 951020D101, " Reactor Building Purge Valve Replacement." The modification was installed to improve the leak tightness of these reactor building isolation valves following valve operation. The inspectors observed the licensee remove the 54-inch valves and replace them with 24-inch valves.
The licensee installed a smaller pipe through the existing penetration and used metal plates to connect the new pipe to the penetration.
Problems encountered during the installation of the modification and postmodification J
testing included cracked welds, lack of proper documentation of work activities, and I
leaks ge of the new valves during local leak rate testing. The licensee appropriately addressed these problems. The inspectors observed good management involvement and quality control oversight during the installation prncess.
Postmaintenance testing of the valves included local leak rate tests, valve stroke time tests, and pressurization of the penetration annulus to verify structural integrity.
Following completion of the modification, the licensee conducted tests to establish a new containment purge design airflow value.
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Conclusions The licensee successfully completed a major modification to replace the Unit i reactor building purge valves. Problems encountered during installation and postmodification testing were appropriately resolved. The inspectors noted good management and quality control oversight of the activity.
M1.3 Unit 1 - Reactor Buildina Sorav System Motor-Ooerated Valve Uoarade a.
Insoection Scone (62707)
The inspectors observed the licensee perform modifications to Unit 1 reactor building spray system motor-operated valves to upgrade various valve components.
Observations included portions of valve disassembly, valve reassembly, limitorque operator cahbration, and modifications to the replacement valve stem.
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Observations and Findings The inspectors observed portions of the Unit 1 reactor building spray system motor-operated valve modification conducted under DCP 963229L101 between April 6 and 27. The licensee performed modifications to Unit 1 reactor building spray system motor-operated Valves CV-2400 and -2401 to upgrade stem keys, the yoke, yoke bolts, and operator base bolts. While working on Valve CV-2401, maintenance technicians j
noticed the print showed that the valve stem had a disk retaining dowel pin but found that the stem did not have a hole to accommodate the dowel pin. The DCP did not provide steps for drilling a hole in the stem to accommodate the dowel pin. Technicians obtained clarification from supervisory personnel and performed the stem modification.
During initial disassembly of Valve JV-2401, technicians encountered a small, but unexpected amount of water priot to the removal of the last ring of packing. Although the system had previously been drained and vented, the system re5!!ed with water due to leakage past an isolation valve. Plant operators had recognized the condition prior to the onset of maintenance, but this information was not communicated to maintenance personnel prior to commencing work. The inspectors observed health physics technicians, mechanics, and operators respond appropriately to the spill. The packing was reinstalled in the valve and the spill was properly contained. Maintenance activities were stopped while the operators verified that boundary valves wern properly positioned and the header was drained. Health physics technicians properly contained and monitored the spill.
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Conclusions Modifications to Unit 1 reactor building spray system motor-operated valves were completed by knowledgeable technicians in accordance with approved gocedures.
Technicians demonstrated a good questioning attitude when unexpected water was encountered during valve disassembly and when a procedural clarification was required for drilling a hole to accommodate a disc reta;ning dowel pin.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Insoection Followuo item 50-313/9707-01. " Penetration Room Ventilation System Fan Performance" On November 14,1997, inspectors observed the licensee perform Procedure 1104.043, Supplement 1," Penetration Room Ventilation Lead System Monthly Test." During the test, the inspectors noticed that the differential pressure indication from the south penetration room was much greater than that measured from the north penetration room and questioned the cause. The piping from the north and south penetration rooms join at the suction of the penetration room fans. With this configuration, the differential pressure readings should be approximately the same, unless something adversely affects the measurements. Although the test met the surveillance test criteria, the inspectors were
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-12-concerned that the instrumentation lines could have a loop seal that could affect the measurement or there was an unidentified source of air leakage into the north penetration room.
On April 23 and 24,1998, the licensee performed Procedure 1104.043, Revision 14,
" Penetration Room Ventilation System,' Supplement 1 " Penetration Room Ventilation Lead System Monthly Test." During this test, the licensee opened the door to the electrical switchgear room corridct and found that the differential pressure reading in the north penetration room apprcached the reading in the south penetration room. The licensee found that an insuumentation line used for measuring differential pressure in the south penetration room was routed to the turbine building while the instrumentation line for the north penetration room was routed to the electrical switchgear room corridor. The licensee determined that the pressure in the electrical switchgear room corridor may not be the same as that in the turbine building depending on the alignment of the ventilation system to that corridor. If the pressure in these areas were not equal, the differential pressures in the penetrations rooms would be different.
The licensee intends to modifying Procedure 1104.043 to allow opening the electrical switchgear room corridor door during performance of the ventilation system tests.
111. Engineering i
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E1 Conduct of Engineering E1.1 Unit 1 - HPl Nozzle inspections a.
Insoection Scoce (92903)
Inspectors reviewed the results of HPI nozzle inspections performed under Job Orders 972526,972459, and 976604. Included was a review of related documentation, radiographs, and boroscope inspections.
b.
Observations and Findinas The inspectors reviewed the results of radiograph and boroscope inspections performed
on HPl injection nozzles during Refueling Outage 1R14 and compared them with the results of inspections performed in 1988. No negative trends or flaws were identified.
The boroscope inspection showed that the HPl Loop C thermal sleeve contained a suspect indication. This indication appeared as a discoloration or small straight scratch on the inner surface of the thermal sleeve. Boroscope films taken in 1988 revealed a similar indication. The licensee considered this indication to be insignificant and assigned an action item associated with CR 1-1998-0478 to develop a resolution. Based upon the results of the inspection, the licensee concluded that there did not appear to be any physical damage on any of the sleeves, the expansion areas of the sleeves were in complete contact with the safe ends, the sleeves appeared to be fully inserted into the
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-13-safe ends, the sleeves had not moved in the direction of the loop pipe as indicated by the weld areas at the ends of the sleeves, and the sleeves had not rotated as indicated by the weld areas et the erid of the sleeves.
c.
Conclusions An inspection of Unit 1 HPl nozzles revealed that the nozzles were intact and free from breakage or cracking. Inspection results were properly recorded and dispositioned.
E1.2 Unit 1 - Decav Heat Removal System isolation Valve Bonnet Modification to Prevent Pressure Lockina a.
Insoection Scone (92903)
In response to information Notice 96-49, " Thermally Induced Pressurization of Nuclear Powcr Facility Piping," which informed licensees of a potential overpressurization problem with piping between normally closed containment isolation valves, and in piping between containment isolation valves that would be closed during a loss of coolant accident, the licensee modified Unit 1 decay heat removal system isolation valves to allow a relief path to prevent this potential pressure locking condition.
b.
Observations and Findinas The inspectors reviewed Plant Change 980138P101," Install a Pressure Relief Design on CV-1050 and CV-1410 to Prevent Pressure Locking," and associated welding packages, completed work requests, and walked down the installed modification. The inspectors found that the modification was installed per the plant change documentation. Welding was accomplished per the design drawings and associated field changes. The responsible engineer was familiar with information Notice 96-49 and had a good understanding of the modification, emergent field changes to the modification, and postmodification testing requirements.
c.
Conclusions Modifications to Unit 1 decay heat removal system isolation valves to prevent pressure locking between were installed as designed.
E1.3 1). nit 1 - Penetration Room Ventilation Seal Maintenance a.
Insoection Scooe (61726 and 37551)
CR 1-1998-022 identified that repetitive tasks requiring replacement of penetration room ventilation system inflatable damper seals every 5 years had not been completed.
Inspectors reviewed the CR, TSs, SAR, and the preventive maintenance engineering
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l evaluation. Addit 2unally, inspectors observed portions of Procedure 1104.043,
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Revision 14, Temporary Change 2, " Penetration Room Surveillance," and interviewed engineering personnel about the condition.
b.
Qblervations and Findinas The penetration room ventilation system is an 1,800 scfm r.ystem designed to collect and process potential reactor building penetration leakage, thus minimizing environmental activity levels resulting from postaccident reactor building leaks. The SAR states that the maximum increased inleakage required to De accommodated by the penett stion room
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ventilation system during recident conditions is 1.25 scfm. The system consists of fans, filter trains, and normal ventilation isolation dampers widch have inflatable seals and associated air accumulators. Periodic survaillance testing verifies that the ventilation system is capable of establishing a negative pressure in the penetration rooms. The inflatable seals were the subject of the CR.
Special tests were performed during plant startup testing in 1974 to reclassify the damper seal air accumulators as nonessential. In response to Generic Letter 88-14
" Instrument Air Supply System Problems Affecting Safety-Related Equipment," the licensee repeated the testing in 1990. This testing demonstrated that the backup air accumulators remained nonessential by demonstrating system operabihty with the damper seals deflated. Test results were documented in Engineering Report 90-R-1029-01.
l CR 1-1998-022 documented the licensee's failure to replace penetration room ventilation system inflatable seals every 5 years as required by the PMEE.
I The licensee evaluated the condition and concluded that the ventilation system remained
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operable. The licensee referenced the testing conducted in 1974 and 1990 which demonstrated that the ventilation system established a negative pressure in the penetration rooms with seals deflated, in addition, the licensee stated that there was no
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evidence of seal degradation. The inspectors questioned the use of 1990 test results to justify current operability of the ventilation system. The inspectors also reviewed historical results of monthly testing performed on the ventilation system and noted a declining trend, since mid-1997, in the negative pressure that the system was able to achieve in the penetration rooms. Since the monthly testing is performed with the seals inflated and the system demonstrated recent signs of degradation, the inspectors questioned the licensee's conclusion that the system would function as designed with the
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seals deflated.
On April 23 and 24, the licensee tested the penetration room ventilation system with and without the seal inflated. The licensee found that the ventilation system established a negative pressure in the penetration rooms with the seals deflated. The licensee also found that the system was capable of establishing a negative pressure even with an open door to the penetration rooms. Since the ventilation system was able to maintain a vacuum in the room with a door open, the licensee concluded that a vacuum could be, a
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-15-I maintained for a much smaller postaccident design inleakage of 1.25 scfm. A comparison of the seal inflated versus seal 6eflated test data indicated that system l
performance was essentially identica!. The licensee concluded that this occurred because the dampers seat sufficiently against the seal and inflating the seal only provides additional margins but does not necessarily improve system performance. The results of this test indicated that the seals remain operable without inflation. Because j
seal testing had historically been performed with the seals inflated, the licensee planned
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10 evaluste the need to perform periodic testing of ventilation system with the seals i
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deflated.
l The licensee indicated that the preventive maintenance tasks associated with the PMEE requirement to replace the seals every 5 years had been deferred because of the complexity of replacing the seals and the impact of seal replacement on related maintenance activities. The justification for delaying the preventive maintenance was based upon the 1974 and 1990 test results coupled with the fact that periodic TS surveillance tests monitored system performance.
l The licensee indicated that a vendor memorandum dated October 11,1996, stated that
"the shelf life (5 years for the seal) was not based on the life of the EDPM (seat material),
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which under ideal conditions had an unproven shelf life of 65 years, but on glues used in the vulcanizing process." Based upon the vendor shelf life and the fact that the air inlet valve was the only component affected by vulcanization, the licensee contended that the 5-year life expectancy was limited to the inflatable function of the seal. Since the seal had been demonstrated operable in 1974 and 1990 without air pressure, the seal remained operable.
The inspectors noted that Engineering Report 90-R-1029-01 documented the 1990 testing which demonstrated that the backup air accumulators remained nonessential.
The inspectors questioned why Engineering Request 974154 was not initiated until 1997 to " downgrade the safety-related classification of the seals from safety related to safety significant with a special procurement requirement." The licensee stated that the desire was identified ir. the 1990 testing documentation; but down grading of systems was a low engineering priority and, therefore, was not conducted at that time. During a quality assurance review of the licensee's response to Generic Letter 88-14, quality assurance personnel initiated Recommendation REC-94-0314-01, dated September 11,1996, which requested resolution of the proposal to downgrade the seals based on the 1990 test. Engineering Request 974154 was initiated as a result of Recommendation 94-0314-01,
i c.
Conclusions l
The licensee effectively demonstrated that the Unit 1 penetration room ventilation system remained operable with damper seals deflated and supported their justification for not replacing the seals every 5 years.
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- 16-E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Insoection Followuo item (IFI) 50-313/9802-01. "Inocerable Control Rod" a.
Insoection Scoos (92903)
NRC Inspection Reports 50-313/98-02; 50-368/98-02 and 50-313/98-03; 50-368/98-03 documented problems that Unit 1 operators experienced with control rods. Following a plant shutdown on January 5,1998, operators identified that one rod, Group 1 Rod 3, would not insert beyond the 5 percent withdrawn position. During the shutdown for Refueling Outage 1R14, this same rod failed to fully insert and an additional rod, Group 2 Rod 6, stuck at the 2.5 percent withdrawn position. During Refueling Outage 1R14, the licensee removed the CRDMs for these two rods and shipped them to the vendor for disassembly and inspection. The inspectors observed the licensee's efforts to determine the cause of the sticking rods and reviewed the results of the detailed inspection of the two CRDMs.
b.
Observations and Findinas In response to the sticking of Rods 2-6 on March 28, the licensee established an event response team to investigate the problem, develop a troubleshooting strategy to identify the cause of the binding, and identify a root cause.
Special work plans were written to use in uncoupling Rods 1-3 and 2-6. The work plans were developed to identify whether the binding was occurring in the CRDM or in the reactor. On April 2 and 3, inspectors observed the licensee uncouple the CRDMs from the control rods. The licensee found that the control rod assemblies for Rods 1-3 and 2-6 inserted fully into the core upon uncoupling, indicating that the binding was occurring intemal to the CRDMs.
The licensee removed the CRDMs for Rods 1-3 and 2-6 and shipped them to the vendor for disassembly and inspection. These two CRDMs were replaced with spare CRDMs.
The inspection of the CRDMs did not identify a conclusive cause for the rods sticking.
The CRDMs were in good material condition and clearance measurements were as expected. The leafsprings on both CRDMs were found to be intact. Although a gouge measuring approximately 1/8-inch wide and 1/16-inch deep was identified in the lower bushing area of each CRDM, the licensee did not believe that this was the cause of the binding because both CRDMs had experienced binding over a longer range of travel than would have been expected from binding within the bushing region.
The licensee determined that the root cause of the CRDM binding was indeterminate.
The licensee evaluated a number of different potential causes and determined that the probable cause was that debris present in the snubber region of the CRDM assembly prevented the lead screw from traveling freely in a range from fully inserted to 5 percent withdrawn. Since inspections revealed that the CRDMs were in good material condition, the licensee believed that the debris came from the RCS. When a control rod is tripped
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Lp-17-and inserts into the core,' reactor coolant flows into the CRDM, which can result in the.
introduction of debris into the CRDM. The clearances within the CRDMs are such that a small particle can create binding.
The event response team report noted that Babcock and Wilcox designed p'lants have never exponenced'a failure of a control rod to fully insert when tripped from a fully.'
withdrawn position. Prior to sticking, Rods 1-3 and 2-6 fully inserted into the core and demonstrated normal rod drop times when tripped from the fully withdrawn position.' The
- licensee concluded that, when tripped from a fully withdrawn position, small amounts of debris present in the CRDM would not cause sticking in the CRDM and would not prevent control rods from performing their safety function to fully insert.
l-Prior to and during startup of the reactor, the licensee exercised control rods on several occasions as part of their normal startup process. As described in Sections 01.4
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and 01.5 of this report, all rods fully inserted when tripped and moved freely through their entire length of travel during rod withdrawal and insertion.
c.
Conclusions The licensee conducted a comprehensive review of the stuck control rod issue and l
developed a good action plan to identify the cause of the sticking.. The licensee concluded that the previous problems associated with control rod sticking were the result of binding in the CRDMs. Although inspection of the CRDM internals for the two stuck -
rods did not reveal a conclusive root cause, the licensee determined that the probable cause was the presence of very small debris in the CRDM which migrated there from the RCS.
E8.2 (Clo*=d) Unreaalved item 50-313/9705-04. "Reador Buildina Sumo Conversion Factor i
Not Accurate" a.
lnspection Scope (92903)
NRC Inspection Report 50-313/97-05; 50-368/97-05 documented the inspectors' review l
of Surveillance Procedure 1103.013, "RCS Leak Detection," resulting in a question about the accuracy of a conversion factor used to convert the indicated reactor building sump
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level in percent to the number of gallons of water in the sump. The inspectors found that using the sump dimensions provided in Civil Engineering Drawings C-97, -111, and -112 yielded a higher conversion factor (31.1 gallons per percent of indicated level) than the one used in the surveillance procedure (26.6 gallons per percent indicated level). During this inspection period, the licen'see measured the dimensions of the Unit 1 reactor building sump and added water to the sump to determine the actual correlation between indicated sump level and volume of water in the sump.
The licensee's measurement of the reactor building sump revealed that the civil
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engineering drawings provided accurate sump dimensions. Using these dimensions, the
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.... y-18-resulting conversion factor was 30.67 gallons of water per percent indicated level. The actual conversion factor would be less, due to components. (valves, instruments, etc.) in the sump.
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During the Unit 1 outage, engineers filled the reactor building sump with known volumes of water and observed the resultant change in level indication as measured by the sump level instrumentation. The licensee found that the change in indicated !avel for each gallon of water added to the sump was not constant over the entire range of indicated level. This was the result of the presence of components in the sump, such as piping, valves, and drain pipes which connect to the sump. Licensee engineers filled the sump to 75 percent indicated level which is where the sump high level alarm annunciated and operators are directed to drain the sump. The licensee identifed three separate regions where the chang in indicated level for each gallon of water added was relatively constant.
Indmated Level Range (Percent)
Gallons ner Percent 1 percent to 8 percent 22.3 8 percent to 48 percent 26.0 48 percent to 76 percent 30.6-Overall Average 26.5 Procedure 1103.013 "RCS Leak Detection," used a conversion factor of 26.6 gallons of water per percent of indicated level. The results of the test revealed that this conversion factor was nonconservative in the range of 48 percent to 76 percent indicated level. The
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licensee revised Procedure 1103.013 to change the conversion factor from 26.6 gallons per percent to 31.0 gallons per percent.
The inspectors detem'ine that the safety consequences of this procedure error were minor. The reactor building sump level instrumentation continued to provide a valid indication of RCS leakage and sump level is typically maintained below 48 percent. In the event of a leak, operators would perform an RCS inventory balance calculation to j
accurately determine the RCS leakrate.-
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c.
Conclusions The licensee resolved an NRC identified discrepancy with a conversion factor used to l
correlate the volume of water in the reactor building sump with indicated sump level. A procedure change was required to correct the nonconservative value in the procedure.
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E8.3. Unit 1 - Testina of Molded Case Circuit Breakers a.
Insoection Scope (92903)
NRC Inspection Report 50-313/97-201; 50-368/97-201 documented an unresolved item which identified that the licensee did not have a program to perform periodic overcurrent
- trip testing of Unit 1 molded case circuit breakers. Subsequently, NRC Inspection Report 50-313/97-21; 50-368/97-21 identified that the licensee had undertaken efforts to develop a testing program for Unit 1 molded case circuit breakers and that testing would
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be conducted during Refueling Outage 1R14. NRC Inspection Report 50-313/98-01; 50-368/98-01 documented that the licensee did not perform periodic testing or maintenance on the electncal fault isolation function of molded case circuit breakers in the 120 Vac instrumentation system. During this inspection period, the licensee
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performed testing on 480 Vac and 120 Vac molded case circuit breakers. Inspectors (
reviewed the results of this testing.
l b.
Observations and Findings Breaker testing for 480 Vac safety-related breakers was performed per Procedure 1416.049, Revision 0, " Containment Penetration Molded Case Circuit Breaker Testing." The licensee selected 10 breakers for testing and was prepared to increase the sample size depending on t..e number of failures. All 10 breakers passed the testing.
The licensee identified 149 scfety-related 120 Vac molded case circuit breakers which required testing. During the testing of the initial sample of 12 breakers,3 failures
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occurred, The licensee expanded their testing to include all of the breakers. The licensee found that 53 of 149 breakers failed the overcurrent trip test, resulting in a 36 percent failure rate. The licensee replaced all of the safety-related breakers with new breakers. The licensee initiated CR 1-1998-0406 to dxument the condition and determine operability and potential deportability of the failures. The licensee sent a sample of failed breakers 'o an outside laboratory for assistance with determination of the failure mechanism. Additional inspection of this issue will be conducted during
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closeout of Unresolved itam (URI) 50-313/97201-14.
l c.
Conclusions Unit i experienced a 36 percent failure rate when 53 of 149 safety-related 120 Vac molded case circuit breakers failed overcurrent trip testing. Similar testing of ten 480 Vac safety-related molded case circuit breakers yielded no failures.
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l-20-IV. Plant Suonort l
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l R1 Radiological Protection and Chemistry Controls R1.1 Unit 1 - Radiological Controls and Personnel Safety Durina Condenser Tube Bundle Reofacement (71750)
The inspectors observed portions of the Unit 1 main condenser tube bundle replacement.
Rigging of the 100 ton condenser tube bundles was in close proximity to the main startup transformers. Proper cautions were observed while moving the bundles in the vicinity of
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the transformers and associated bus work. Components and cranes were grounded to protect personnel against any charge that may have been induced in the bundles due to the proximity to overhead transmission lines. The rigging plan and procedures were present at the job site and referenced by personnel as required. Safety personnel were present during rigging operations. Personnel properly utilized safety hamesses. Due to potet tial contamination of the condenser tube bundles, the area where the bundles were being moved was posted as a potentially contaminated area. Health physics personnel were observed conducting required surveys during the evolution.
R1.2 Unit 1 - Decontamination of Potentially Contaminated Worker a.
Insoection Scooe (71750)
On April 26, inspectors observed health physics personnel monitor and perform decontamination activities on an individual who had facial contamination. The contamination occurred while the individual was performing work associated with steam generator manway installation.
b.
Observations and Findinas Interviews indicated that the contaminated worker was wearing anticontamination clothing required by the radiological work permit. The licensee determined that the individual had ingested a small amount of cobalt-60 and periodically monitored the particle until it had passed through the individual. The licensee calculated that the dose received by the individual as a result of the intemal contamination was 85 mrem committed effective dose equivalent. The licensee thoroughly briefed the contaminated individual about the status of the particle and kept him informed of the status of the contamination.
c.
C.onclusions Health physics technicians took appropriate actions in response to an individual with facial and internal contamination.
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-21-S1 Conduct of Security and Safeguards Activities
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S1.1 Unit 1 -Identification of Foreian Materialin Main Turbine Generator Bearinas Classified as Potential Tamoerina Event a.
Insoection Scooe (71750. 92904)
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On April 7,1998, during disassembly of the Unit 1 main turbine generator, the licensee identified the presence of foreign material in the Number 4 bearing between the shaft and bearing on the oilinlet side of the bearing. The licensee concluded that foreign material could have been intentionally placed in the bearing and reported the finding to the NRC in accordance with 10 CFR 73.71(b). The inspectors reviewed the licensee's response to this finding.
b.
Observations and Findings During the disassembly of the Unit 1 main turbine generator on April 7, the licensee discovered two pieces of foreign material in the Number 4 bearing between the shaft and bearing on the oil inlet side of the bearing. The items appeared to be cut sections of threaded carbon steel bolts, one piece measuring 1 inch by 3/8 inch and the other measuring 3/4 inch by 1/8 inch. While there was evidence that both pieces had rubbed against the main turbine generator shaft, the shaft was not damaged. The licensee believed that the material had been there since the last refueling outage and identified two possible means for the material to be introduced, either poor foreign material exclusion controls or the intentional placement of the materialin the system. Since the licensee concluded the potential existed that the foreign material could have been intentionally placed in the bearing, the licensee reported this event to the NRC in accordance with 10 CFR 73.71(b).
The licensee inspected the remaining turbine generator bearings not previously scheduled for disassembly during Refueling Outage 1R14. On April 14, the licensee identified additional foreign material in Bearing 7. The material included a 13/4-inch and a 3/8-inch washer imbedded in the babbitt of the bearing. A gouge in the babbitt indicated that a third object was present, but the licensee believed that the material had worn away into smaller pieces which were flushed out of the bearing. No additional foreign material was identified in the other bearings inspected. The foreign material was removed and the affected components were repaired. Other actions taken by the licensee included briefing appropriate personnel on the finding, reviewing existing foreign material exclusion controls to verify that they were adequate, and enhancement of security on the turbine deck while work was being performed on the turbine. A security investigation was also initiated. At the conclusion of the inspection period, the licensee had not completed their security investigation.
On May 4,1998, the licensee submitted Safeguards Event Report 50-313/98-S01-00 to the NRC in accordance with 10 CFR 73.71(b)(2). In this report, the licensee indicated that they could not determine if the foreign material was introduced accidentally or
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intentionally and, therefore, the root cause could not be conclusively determined.
Adddional inspection will be conducted to review the results of the licensee's security investigation as part of the closeout inspection for the safeguards event report.
c.
Conclusions The licensee conducted appropriate inspections in response to a potential tampering event associated with foreign material found in bearings on the Unit 1 main turbine generator.
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V. Manaaement Meetinas j
l X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 13,1998. The licensee acknowledged the findings presented.
i The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED
Licensee G. Ashley, Licensing Supervisor
'B. Allen Unit 2 Maintenance Manager T. Brown, Unit i Outage
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- B. Beard, Unit 2 Electrical Superintendent
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M. Chisum, Manager, Unit 2 System Engineering D. Denton, Director, Support S. DeYoung, Planning Supervisor -
P. Diertrich, Manager, Unit 1 Maintenance
. R. Edington, Plant Operations General Manager B. Gordon, Superintendent, Unit 2 Mechanical Maintenance P. Harris, Shift Superintendent, Unit 1 Operations D. James, Acting Director, Nuclear Safety P. Kearney, Supervisor, Modifications Engineering J. Kowalewski, Unit 1 System Engineering Manager R. Lane, Director, Design Engineering -
M. Smith, Engineering Programs Manager
' A. South, Licensing J. Vandergrift, Quality Director H. Williams, Superintendent, Plant Security T. Wood, First Line Supervisor, Unit 2 Mechanical C. Zimmerman, Unit 1 Plant Manager INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
. Plant Operations IP 71750:
Plant Support Activities IP 92903:
Followup - Engineering IP 92904:
. Followup - Plant Support IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED l
Opened L
50-313-9804-01 VIO Improper Temporary Release of Hold Card (Section 04.1)
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-3-Closed 50-313/9707-01 IFl Penetration Room Ventilation System Fan Performance (Section M8.1)
50-313/9802-01 IFl Inoperable Control Rod (Section E8.1)
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50-313/9705-04 URI Reactor Building Sump Conversion Factor Not Accurate (Section E8.2)
Discussed 50-313/97201-014 URI Lack of Testing Unit 1 Molded Case Circuit Breakers (Section E8.3)
LIST OF ACRONYMS USED A
condition report CRDM control rod drive mechanism CRS control room supervisor DCP design change package EFW emergency feedwater HPl high pressure injection IFl inspection followup item RCS reactor coolant pump SAR Safety Analysis Report TS Technical Specification URI unresolved item j
VIO violation L
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