IR 05000361/1998003
| ML20217F364 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 03/25/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20217F354 | List: |
| References | |
| 50-361-98-03, 50-361-98-3, 50-362-98-03, 50-362-98-3, NUDOCS 9803310377 | |
| Download: ML20217F364 (22) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.: 50-361 +
50-362 I
l License Nos.: NPF-10 NPF-15 l
Report No.: 50-361/98-03 50-362/98-03 l
Licensee: Southern California Edison C Facility: San Onofre Nuclear Generating Station, Units 2 and 3 l Location: 5000 S. Pacific Coast Hwy.
l San Clemente, California Dates: February 1 through March 14,1998 Inspector (s): J. A. Sloan, Senior Resident inspector J. G. Kramer, Resident inspector J. J. Russell, Resident inspector D. G. Acker, Senior Project inspector
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Approved By: Dennis F. Kirsch, Chief, Branch F l Division of Reactor Projects i
ATTACHMENT: Supplemental Information
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9803310377 980325 PDR ADOCK 05000361 G PDR
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-2- 1 EXECUTIVE SUMMARY
' l San Onofre Nuclear Generating Station, Units 2 and 3
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NRC Inspection Report 50-361/98-03, 50-362/98-03 This routine, announced inspection included aspects of plant operation, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspectio Ooerations
Operators were thorough and methodicalin preparing for and conducting routine and nonroutine evolutions associated with completing an outage on Unit 2 and commencing an outage on Unit 3. Close management and supervisory oversight o'f operational activities was evident. Procedure use and operator communications were excellent (Section 01.1).
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Conduct of an attempt to perform a reactor startup was excellent overall. The prejob briefing for the startup was thorough, and management oversight was excellent. The operators' response to the failure of regulating group control element assemblies (CEAs) to move in the manual sequential mode was consistent with procedural guidelines (Section 01.2).
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The draindown of the Unit 3 reactor coolant system (RCS) to midloop conditions was conducted in a professional manner, with good management oversight, attention to maintaining parameters in specification, and good performance of the level monitoring systems. Minor isolated weaknesses were observed in the areas of annunciator response, operator attention to the appropriate computer display screen for level information, and procedural stipulation of time-to-boil data (Section 01.3).
A noncited violation was identified by the inspectors as a result of the failure of a nuclear l
plant equipment operator (NPEO) to follow the procedure for the racking in and out 4160 V breakers (Section 04.1).
Inadequate communications between the work process center and the control room resulted in the Unit 2 control room operators being uncertain as to why a saltwater I
cooling (SWC) pump was removed from service, and procedural expectations for initiation of equipment deficiency mode restraint (EDMR) paperwork for inoperable equipment were not met (Section 04.2).
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Operations management demonstrated excellent attention to detail during a routine review of operator logs in idenNfying improper operator response to a reactor trip circuit I breaker (RTCB) problem (Section 07.1).
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b-3-Ma ntenance
Seven maintenance and four surveillance activities were observed to generally be performed in a thorough and professional manner by knowledgeable personne Supervisors and system engineers were frequently observed monitoring job progress (Sections M1.1 and M1.2).-
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A noncited violation was identified as a result of the failure of electricians to follow the procedure during surveiliance testing of the fire protection system. The licensee response to the failure to follow procedure was prompt and the corrective actions were appropriate (Section M1.3).
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The containment cleanup at the end of the Unit 2 midcycle outage was generally very effective, although the inspectors identified some debris in a steam generator (SG)
keyway, including a metal socket, that could interfere with the thermal expansion of the RCS (Section M2.1).
Enoineerina
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One violation of 10 CFR Part 50, Appendix B, Criterion V, was identified by the inspectors as the result of the licensee's failure to ensure that the locking tabs were properly bent on several nuts and bolts securing the mechanical nozzle seal assemblies (MNSAs), indicating a weakness in the skill of the craft and in the attention to detail during Quality Control inspections. The licensee inadvertently over-drilled the counterbores on two holes on each of the two pressurizer MNSAs, but the error was identified by the licensee during the inprocess Quality Control inspections. The j
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over-drilling was partially the result of the licensee's intense focus on the most impottant '
parameter (total hole depth), that led to reduced focus on the less immtMm parameter 1 (counterbore depth). Other aspects of the MNSA installations were in accordance with :
the design (Section E2.1).
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The licensee's response to a failed 6-inch moisture separator reheater (MSR) drain line was prompt and thorough. Engineering's preliminary assessment of the failure, which was caused by flow-accelerated corrosion (FAC) was rigorous (Section E2.2).
Two Nuclear Oversight Division audits of technical organizations were found to be ;
effective in assessing performance. The licensee's apparent cause deteminations, corrective actions and followup on open items were good (Section E7.1).
Plant Sucoort
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Two of five contract workers were observed by the inspectors as not complying with their radiological exposure permit (REP). The workers' poitable electronic dosimeters (PEDS) were being worn inside their protective clothing while their REP required the PEDS to be worn outside their protective clothing. This resulted in a noncited violatio In this instance, attention to the requirements of the REP was weak (Section R1.1).
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A Maintenance technician failed to maintain visual observation of contractor working in the PA, which was a violation of the Physical Security Plan requirements for escorting visitors (Section S1.1).
An unresolved item was identified regarding the appropriate security classification of the temporary equipment used for filtering the emergency diesel generator (EDG) fuel oi The temporary equipment was outside the vital area, but the fuel oil storage tanks are classified as vital equipment, and the EDGs were operable during the filtration process (Section S1.2).
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Report Details Summary of Plant Status l Unit 2 operated in Mode 5 from the beginning of this inspection period until February 20,1998,
! when a plant heatup was begun. The reactor was made critical and the unit was synchronized j to the grid on February 22,1998. Power was increased to 90 percent, where the unit operated l
until February 25, when power was reduced to 20 percent to allow inspection and repair of an MSR drain line. A power increase was initiated on February 28. The unit operated at essentially 100 percent power from March 3,1998, until the end of this inspection perio Unit 3 was operated at essentially 100 percent power from the beginning of this inspection
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period until March 7,1998, when the unit was shut down to commence a midcycle outage. The l unit was in Mode 5 at the end of this inspection period.
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Conduct of Operations O1.1 General Comments The inspectors observed routine and nonroutine operational activities throughout this inspection period. Some of the activities observed included:
Conduct of routine shift turnovers (multiple observations)
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Monitoring of 480 V breaker line starter inspections (Unit 3)
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Operating at steady state midloop conditions (Units 2 and 3)
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Midloop Operations management turnover (Unit 2)
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Performing reactor coolant pump sweeps with the RCS solid (Unit 2)
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Starting reactor coolant pump 2P001 (Unit 2)
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Changing in-service letdown backpressure regulating valves (Unit 3)
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Lowering and raising reactor power (Unit 2)
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Starting auxiliary feedwater (AFW) Pump 3P140 (Unit 3)
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Shutting down the reactor from 60 percent power and entering Mode 3 (Unit 3)
Operators were thorough and methodical in preparing for and conducting routine and
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nonroutine evolutions associated with completing an outage on Unit 2 and commencing an outage on Unit 3. Close management and supervisory oversight of operational activities was evident. Procedure use and operator communications were excellen Specific comments on activities observed are discussed belo .2 Reactor Startuo after Midcvele Outaae - Unit 2 Insoection Scope (71707)
The inspectors observed control room preparations for and initiation of reactor startup in accordance with Procedure SO23-3-1.1, " Reactor Startup," Revision 17. The final f
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-2-approach to criticality was not observed, but was confirmed by reviewing licensee record I Observations and Findinas j l
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The inspectors observed the prejob briefing for initiation of Procedure SO23-3-1.1,
- Attachment 2. The prejob briefing was led by a licensed operator. The operator discussed all the precautions and prerequisites. During the procedure discussion, each action was assigned to a specific individual. At the completion of the procedure discussion, the assigned operators reverified their assigned actions. The control room staff and Operations management personnel then discussed potential problems and j
corrective actions, with an emphasis on safe reactivity control.. Finally, reactor engineering personnel gave a brief overview of expected core performance and discussed their function in evaluating the approach to criticality. During the prejob briefing, extra licensed operators were monitoring control board indications. In the j middle of the prejob briefing, an annunciator alarm was received for high differential pressure across the primary side of a component cooling water heat exchanger. Control room supervision temporarily suspended the prejob briefing, assessed the condition of the heat exchanger, and assigned the extra operators actions to resolve the conditio The inspectors considered the prejob briefing to have been very well don After completion of the prejob briefing and associated prerequisites, the licensee started an approach to criticality. However, at an early step, no regulating group CEA response , ,
occurred when the operator attempted to withdraw the CEAs in the manua! sequential !
mode. After sufficient time to verify that no motion was occurring, the licensed operator i suspended the withdraw attempt. After discussions with the operating crew and Operations management, the control room supervisor (CRS) directed the operators to attempt to exercise each regulating group in the manual group mode. The inspectors !
asked the CRS if this operation was in accordance with the procedure. The CRS ;
determined that an optional exercising of the regulating groups was part of the l
procedure, which had originally been considered unnecessary for startup. The licensee l completed the exercising of Group 1 regulating CEAs successfully in the manual group .
mode. The licensee then re-entered the startup procedure and was again unsuccessful 1 L in obtaining any CEA movement in the manual sequence mode. The licensee then l attempted to exercise the remaining regulating CEAs. Group 2 did not respond in the manual group mode. The licensee stopped the procedure and initiated troubleshooting actio i The licensee successfully completed the reactor startup after replacing a timer card in the control element drive mechanism control syste Conclusions Conduct of an attempt to perform a reactor startup was excellent overall. The prejob ,
briefing for the startup was thorough, and management oversight was excellent. The l I
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operators' response to the failure of regulating group CEAs to move in the manual sequential mode was consistent with procedural guideline .3 Midlooo Ooerations - Unit 2 I
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The inspectors observed the draindown of the Unit 3 RCS from about 38 percent pressurizer level to about 26 inches from the bottom of the hot leg. The RCS was in Mode 5 about 120 *F with the reactor vessel fueled and the head tensioned. The !
draindown was conducted on March 9-10,1998, in increments from 38 percent !
pressurizer level to 40 inches from the bottom of the hot leg, then from 40 inches to 36 inches, then from 36 inches to 26 inches. The hold points were established so as to maintain a greater than 16-minute time to boil. The inspectors also reviewed portions of Procedures S023-3-1.8, " Draining the RCS," Revision 12, and SO23-5-1.8.1,
" Shutdown Nuclear Safety," Revision Observations and Findinas ,
, 1 Overall, the draindown was conducted by the control room operators in a professional manner. Management oversight was continuous throughout the drain down. The control room operators displayed good attention to maintaining shutdown cooling flow and reactor coolant temperature within procedural and Technical Specification (TS)
requirements. Level monitoring systems, including the reactor water level indication system, the diverse level monitoring system, the heated junction thermocouples (HJTCs), and the local site glass, all performed well with essentially no hardware or calibration problems. However, three minor weaknesses were observed by the inspector )i in one instence, poor communications between the common control operator (CO) and the Unit 3 operating crew led to a "CFMS (critical functions monitoring system)/QSPDS (qualified safety parameter display) Input or Hardware Trouble" annunciator being left unnecessarily illuminated. The annunciation had no reflash capability. These systems provided level indications. The condition was cleared after the inspectors questioned {
the reason for the annunciation. The annunciation illuminated during the draindown ]a prejob briefing. The common CO, who had responsibility for acknowledging and i ensuring operating crew cognizance of this annunciator, thought that the operating crew j i intended to leave the annunciation illuminated throughout the drain down. The l operating crew actually intended to reset the system parameter and clear the j annunciation, which was done after the inspectors' question l In one instance, the Train A quelified safety system parameter display system display screen was not set to an appropriate page. There are two trains of HJTCs, and HJTC 6 was only operable on Train A. One of the stop criteria for the draindown was if HJTC 6, which is at 21 inches above the bottom of the hot leg, became voided of wate Procedural guidance was to secure the drain down if HJTC 6 temperatures began to
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diverge, indicative of voiding. The Train A screen was set to monitor core exit temperatures, precluding the CO from detecting early temperature divergence for HJTC 6, which was not displayed on the core exit temperature screen. The condition was corrected in response to the inspectors' observation.
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l Procedure SO23-3-1.8 was confusing regarding the data to be used for time-to-boil calculations. This procedure referred the user to a table in Procedure SO23-5-1.8.1, which had time-to-boil data. However, the intended data for this draindown was located in the core physics data book. This caused some confusion for control room operators l during the drain down to 36 inches. The time-to-boil calculations used to update a
control room placard and to operate the plant consistently used the intended data.
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The draindown of the Unit 3 RCS to midloop conditions was conducted in a professional manner, with good management oversight, attention to maintaining parameters in -
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specification, and good performance of the level monitoring systems. Minor isolated weaknesses were observed in the areas of annunciator response, operator attention to the appropriate computer display screen for level information, and procedural stipulation l of time-to-boil dat Operator Knowledge and Performance 04.1 4160 V Breaker Ooeration - Unit 2 Inspection Scope (71707)
The inspectors monitored the performance of an NPEO during the racking evolution of 4160 V breakers, in addition, the inspectors reviewed Procedure SO23-6-2.1,
"4160 Volt Air Circuit Breakers," Revision 2, and discussed the NPEO's performance l ~ with the shift superintendent (SS) and Operations management.
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On February 25,1998, the inspectors observed the NPEO perform Procedure SO23-2-8, "SWC System Operation," Revision 18, Step 2.7, that directed the operator to rack out Breaker A04-10 and rack in Bre'a ker A04-11. The inspectors observed the NPEO rack out Breaker A04-10 to the disconnect position. The inspectors l- observed that the NPEO did not have the Procedure SO23-6-2.1 present during the i
' racking evolution. When the inspectors observed that the NPEO had removed the
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Kirk-key from the breaker and began fastening the cubicle door closed, the inspectors
,. questioned the NPEO about discharging the closing springs. The NPEO indicated that the springs could be discharged, but then the breaker would have to be further removed from the disconnect condition and returned to the disconnect position. The inspectors asked the NPEO if direction had been given to leave the breaker in the disconnect position with the springs charged. The NPEO indicated that no such direction had been
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-5-I given. The inspectors then informed the NPEO of the procedural requirement to discharge the springs. The NPEO reviewed the copy of Procedure SO23-6-2.1 that the inspectors were using to follow the evolution, agreed that the springs should be discharged, and discharged the The inspectors observed the NPEO proceed to rack in Breaker A04-11. The inspectors observed that the closing springs for the breaker were charged. Procedure SO23-6- required that the closing springs be discharged prior to racking the breaker in from the
! disconnect position. The inspectors observed that the NPEO was about to rack the l
breaker in and informed the NPEO of the requirement to discharge the springs. Again, the NPEO reviewed the inspectors' copy of the procedure and agreed that the springs were required to be discharged prior to racking the breaker in, and discharged them.
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maintained covering the applicable procedures recommended in Regulatory Guide 1.33, l Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, -
recommende procedures for the electrical AC system. Procedure SO23-6-2.1 provides instructions for the operation of the 4160 V breakers. The failure of the NPEO to perform Steps 6.2.4 and 6.3.3 of Procedure SO23-6-2.1 was a violation of TS. This failure constitutes a violation of minor safety significance and is being treated as a i noncited violation, consistent with Section IV of the NRC Enforcement Policy i
(NCV 361/98003-01).
The inspectors discussed the NPEO's performance with the SS. The SS indicated that the expectations were that the procedure was not required to be in hand, but the l expectation was that the NPEO be knowledgeable of the procedure requirements and l that the procedure be followed. Since the NPEO was going to leave Breaker A04-10 l with the closing springs charged and Breaker A04-11 was found with the closing springs
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charged, the SS directed an operator to verify the closing spring position of the remaining 4160 V breakers that were in the disconnect position. No other closing springs were found charged. In addition, the SS initiated an action request (AR) to evaluate the issue. The licensee issued a Priority 2 reading for all operators on the subject of charging springs on 4160 V breakers.
I c. Conclusions A noncited violation was identified as a result of the failure of the NPEO to follow the procedure for the racking in and out of 4160 V breakers. The licensee's corrective actions were prompt and thoroug I, ,
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- .2 Ooerator Knowledae of Eauioment Status - Unit 2 l
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The inspectors performed a routine walkdown of the Unit 2 control boards and questioned operators about the status of equipment. The inspectors discussed the observations with Operations managemen Observations and Findinas On March 11,1998, the inspectors performed a walkdown of the Unit 2 control boards and observed a clearance on SWC Pump 2P307. The inspectors questioned the control room operators about why the pump had a red clearance tag on the control switch. The operators (CO and CRS) were not sure why the pump had a clearance on it, but suspected it was due to the work associated with the Unit 3 outage. SWC Pump 2P307 l was in the Unit 3 intake area. The operators confirmed with work control that the pump l was indeed removed from service due to Unit 3 intake work.
i l The inspectors reviewed the EDMR log book and did not observe an entry for SWC Pump 2P307. The inspectors questioned the CRS about the lack of an entry and the CRS indicated that a flag EDMR would bc created.
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The inspectors discussed the observations of the weakness of the operators' knowledge and the lack of an EDMR entry with the Operations superintendent. The Operations superintendent followed up on the inspectors' concems and leamed that the SWC pump was removed from service on the previous shift. The licensee had performed a work l authorization modification that included Pump 2P307. Subsequently, the work process l CO entered the control room and attached a red clearance tag to the previously racked out pump switch (one SWC pump is racked out in each SWC train). The CO and the CRS were unaware of the tag being placed on the pump; therefore, the status of the pump was not revealed to the oncoming shift during shift tumover. In addition, the oncoming shift did not question the reason for the pump being removed from service.
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l- The licensee initiated an AR as a result of the inspectors' questioning. The licensee concluded that inadequate communication between the work process CO and the l control room was the cause of the problem. In addition, the licensee identified that the work authorization modification check list was deficient in that it did not have a line item '
to evaluate whether or not the additional component had TS or EDMR paperwork applicability. The licensee planned to change the check list to include such a step. The Operations superintendent indicated that expectations for communications and flag EDMR initiation had not been met.
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l Conclusions inadequate communications between the work process center and the control room resulted in the Unit 2 control room operators being uncertain as to why a SWC pump i
I was removed from service, and procedural expectations for initiation of EDMR l paperwork for inoperable equipment were not me l
4 Quality Assurance in Operations O7.1 Suoervisorv Review of Control Room Loas - Unit 2 ; Insoection Scone (71707)
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The inspectors reviewed AR 980200074, which documented an error identified during a supervisory review of Operations log Observations and Findinas Operations management personnel performed a monthly review of operator logs on February 2,1998, and determined that operators had incorrectly assessed an RTCB indication failure on January 21,1998. The RTCB had failed to indicate closed during monthly testing.
l The operators had correctly declared the RTCB inoperable, and opened it, as required ,
l by TS 3.3.4, Action A. Action A states that with one channel of manual trip, RTCBs, or '
l initiation logic inoperable in Mode 1 or 2, operators are required to open the affected RTCBs within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The operators had failed to realize that the channel censisted of two RTCBs, and that both RTCBs were required to be opene The failed RTCB was replaced and declared operable within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of the failure, satisfying the TS action requirements that were in effect when the 1-hour requirement i was not satisfie l l
The licensee determined that the operators had failed to recognize a difference in the action requirements between the improved TS, implemented in 1996, and the previous TS. The licensee determined that operators had not adequately reviewed the TS, the RTCB surveillance procedure had not alerted the operators to the action requirements, r and that the change from a long standing practice of only declaring the affected breaker l inoperable all contributed to the erro The inspectors reviewed the applicable old TS (TS 3.3.1 and Table 3.3-1). Table 3.3-1
indicated that a channel was comprised of two RTCBs. However, the TS did not specify opening both RTCBs as a required action in Modes 1 and a 0
-8-l Conclusions Operations management demonstrated excellent attention to detail during a routine review of operator logs. The reviewer identified that operators had not opened both RTCBs in a channel after one RTCB failed a surveillance test, as directed by TS. This was a subtle difference between the improved TS and the previous TS that the operators had not recognized. However, TS requirements were satisfied by restoring the operability of the RTCB within the required action tim II. Maintenance M1 Conduct of Maintenance
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M1.1 General Comments on Maintenance Activities Insoection Scoce (62707)
The inspectors observed all or portions of the following work activities:
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SG 2E089 tube plugging (Unit 2)
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Low pressure safety injection Pump 2P016 miniflow Valve 2HV8163 inspect for lubrication (Unit 2)
a inspect reversing line starters on 480 V breakers (Unit 3)
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Replace hydraulic recirculation pump for feedwater block Valve 3HV4051 (Unit 3)
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Replace Breaker 3BY41 line starter (Unit 3)
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Clean and adjust voltage regulator potentiometer for EDG 3G002 (Unit 3)
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Filtration of EDG 2G003 fuel oil (Unit 2) Observations and Findinos The inspectors found the work performed under these activities to be thorough. All work observed was performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applicable, appropriate radiation l controls were in place.
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-9-M1.2 General Comments on Surveillance Activities insoection Scoon (61726)
The inspectors observed all or portions of the following surveillance activities:
2HV0517 Loop 2 hot leg sample isolation valve quarterly valve test (Unit 2)
CEA/RTCB operability test (Unit 3) .
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Inservice test of AFW Pump 3P140 (Unit 3)
AFW system check valve flow test (Unit 3) Observations and Findinas -
The irtspectors found all surveillances performed under these activities to be thoroug All surveillances observed were performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applicable, appropriate radiation controls were in plac In addition, see the specific discussions of surveillances observed under Section M1.3, belo M1.3 AFW Pumo Room Preaction Valve Test - Unit 3 Insoection Scone (61726. 71750)
The inspectors observed electricians perform Procedure SO23-1-2.73, " Testing of Actuation Detectors - Outside Unit 3 Containment," Revision 1. The inspectors discussed the performance of the electricians during the surveillance with the Emergency Preparedness (EP) manager and the electrical general forema Observations and Findinas j On February 10,1998, the inspectors observed electricians perform sections of
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Procedure SO23-I-2.73. Specifically, the inspectors' observed the fire detection system testing on the AFW building deluge Valve S32301MU49 The electricians performed a channel functional test of nine thermal detectors. The electricians tested the thermal detectors using a heat gun. Then, located at the alarm panel outside the AFW building, the lead electrician checked off the detectors being tested; however, the detectors being checked off did not correspond to the detectors being heated. The inspectors questioned the electrician about the discrepancy and the electrician indicated that if a detector failed then the failed detector would be positively identified. The electrician failed to meet the requirements of Step 6.4.8, which stated, in i
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l l part, to check off the items completed on the maintenance data record form. The maintenance data record form (Attachment 7) included a note that stated, in part, to check off detector stations as testing was complete The electricians performed a supervisory test of the system. During the performance of ,
the test, the electricians lift a lead, check for trouble light and annunciation, and l reterminate the lead. The electricians perform this action on four different leads. The !
l electricians performed the evolution with the procedure available, but not opened. The
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electricians did not perform two steps: Step 6.5.3 directed, in part, to press the trouble silence button; and Step 6.5.5 directed, in part, to return the trouble silence button to normal by pressing the normal button. When informed by the inspectors about the l
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missed steps, the electricians reperformed the evolution. During subsequent interviews, the licensee identified that the lead electrician incorrectly believed that he could bypass the steps since he was only silencing the alarm and he was accomplishing the same i
task by reterminating the lea Unit 3 TS 5.5.1.1.a requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, l
Revision 2, Appendix A, February 1978. Regulatory Guide 133, Appendix A, recommends procedures for fire protection system functional tests. The purpose of Procedure SO23-1-2.73 was to perform a system functional channel and supervisory test l ' of the actuation detectors outside Unit 3 containment. The failure of the electricians to perform Steps 6.4.8,6.5.3, and 6.5.5 of Procedure SO23-1-2.73 was a violation to T This failure constitutes a violation of minor safety significance and is being treated as a noncited violation, consistent with Section IV of the NRC Enforcement Policy (NCV 362/98003-02).
The inspectors observed the electricians perform the system restoration. The procedure directed, in part, to shut drain Valve 3BSH8987. The lead electrician performed the initial check of the valve. The lead electrician then pointed to the valve and directed a second electrician to " verify that valve is closed." The second electrician performed the second person verification and checked the valve was closed by attempting to turn the valve in the close direction. The second verifier did not look at the valve identification tag. The inspectors looked at the tag and observed the label indicated "S32301MU499 Drain Valve." The inspectors subsequently determined that the electricians had closed and checked the correct valve. The licensee initiated action to resolve the difference
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between the label and the procedur The inspectors discussed the observations with the EP manager. The EP manager indicated that expectations for procedural compliance, valve verification, cross-checking, and communications were not met. The licensee initiated an AR to evaluate the electricians' performance. On February 13, the licensee conducted a " stand down" of the fire protection improvement team to focus on program compliance, to review the i journeyman's responsibilities, and to review prejob briefing requirements. In addition, ;
the licensee planned to evaluate Procedure SO23-I-2.73 for enhancement l l
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l A noncited violation was identified as a result of the fa:Iure of electricians to follow the i
procedure during surveillance testing of the fire protecton system. The licensee response to the failure to follow procedure was prompt and the corrective actions were appropriat M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Review of Material Condition Durina Plant Tours
- On February 20,1998, the inspectors walked down Unit 2 containment. This was the same day as the licensee's final containment closeout inspection. in general, the containment was very clean. However, the inspectors observed debris in the key ways for SG 2E088. The debris included a paint brush, a metal socket, and plastic wrappin The metal socket could have interfered with movement of the SG base plate in the key way as the RCS expanded during heat up. Health Physics (HP) personnel removed the debris. The inspectors concluded that the containment cleanup had been very effective, but that in one work area debris had been left that could have affected plant performanc Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E MNSA Installation - Unit 2 Insoection Scoce (37551)
The inspectors reviewed activities associated with the installation of MNSAs on the pressurizer, SG bowl, and RCS hot leg piping. The inspectors inspected the installations in process and after completion. The inspectors reviewed the following documents:
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ARs 980201737,980102087, and 980200400
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Construction Work Orders 98013360000, 97110434000, 98013319000, and 98013356000
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Procedure SO23-411-57-12 " Engineering Procedure for the Installation of the Mechanical Nozzle Sea! Assemblies for SONGS Units 2 and 3," Revision 3 1 Observations and Findinas j
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i The licensee requested NRC approval for installation of MNSAs as an alternate repair method for RCS instrument nozzles. The original nozzles contained Inconel-600, which
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-12-a is susceptible to primary water stress corrosion cracking. This issue was discussed in NRC Inspection Report 50-361; 362/97-15. NRC approval of the use of the MNSAs under certain circumstances was documented in a February 17,1998, letter from the NRC to the license )
An MNSA consists of, in general terms, a compression sealing device bolted to the base metal (RCS piping, pressurizer shell, or SG bowl) and an anti-ejection restraint. The - 1 installation requires drilling and tapping approximately 1-inch deep holes into the base meta i The licensee installed two MNSAs on the bottom portion of the pressurizer. These were l planned prior to the midcycle outage and the licensee had requested that the installations be approved permanently. NRC granted interim approval, and is still considering the request fcr permanent approva Four other MNSAs were installed, under an interim approval, to stop leakage identified during licensee inspections at the beginning of the midcycle outage. Two MNSAs were installed on the RCS hot leg piping to SG 2E088 and two were installed on the i SG 2E089 bowl.
l After drilling the holes for the MNSAs on the pressurizer, the licensee's Quality Control ' inspectors determined that the counterbore holes for two alignment holes for each of the MNSAs were drilled too deeply. The overall hole depths were acceptable, but the counterbore depths exceeded the design. The design depth of the counterbore was 0.380 i 0.020 inches, but the actual depths varied from 0.410 to 0.472 inches. The licensee documented the deficiency in AR 980200237, from which Nonconformance Report (NCR) 980200237 was generated. The NCR was dispositioned to accept the conditions as-is. The licensee determined that the cause of the over-drilling was the use l of a specially designed "go/no go" gauge used by the craft to ensure that the holes did I
not exceed the 1.38-inch maximum depth. The go/no go gauge was shaped to indicate both the counterbore and the main hole depth. The drilling was performed using a single specially designed bit that drilled the main hole and the counterbore simultaneously, in checking the progress of the drilling, the craft focused on not i: exceeding the depth of the main hole. However, the bit was designed so that if the l counterbore depth was not exceeded, the maximum main hole depth would not be exceeded. After the drilling was completed, Quality, Control inspectors measured both the main and counterbore depths using a depth micrometer and discovered the over-drilling. The inspectors reviewed the NCR disposition and determined that the licensee's actions were acceptabl The MNSA design required locking tabs to be installed on all the nuts. On February 16,1998, the inspectors observed that several of the locking tabs were not properly bent over on four of the MNSAs. (The inspectors could not inspect the two pressurizer MNSAs without reinstallation of some scaffolding.) Some locking tabs were bent up at points (instead of at flats) on the nut, and others were bent up too far from the nuts so that nut rotation would not have been obstructed by the locking tab i
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Subsequently, the licensee reinspected all six MNSAs and confirmed the inspectors'
findings. SpecMcally, the licensee informed the inspectors that 16 deficiencies of the 192 total required tabs were confirmed:
Location Nozzle Identification Number of deficient lockina tabs
! Pressurizer ~ 2LT0110-1 2 l Pressurizer 2LT0110-2 1
! RCS hot leg 2TWO139-B 5 RCS hot leg 2TWO122-4 4 SG 2E089 2PDT0976-1 ' 3 SG 2E089 2PDT0978-2 1 The pressurizer MNSAs had been inspected by the Construction Quality Control personnel, and the other four MNSAs had been inspected by both construction and licensee Quality Control personnel. Additionally, the Nuclear Construction engineer had
' performed the final acceptance walkdowns of the pressurizer and SG MNSAs. The final accep" ace of the RCS hot leg MNSAs had not yet been performe The construction work orders for the MNSA installations implemented Procedure SO23-411-57-12. Step 8.2.22 of this procedure states that "After torquing of
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' all threaded fasteners is complete, bend at least one tab of all Retainer Washers against the flats in its corresponding threaded fastener (either Hex Bolt or Hex Nut) and at least one tab against the adjacent component (either the Upper Flange or Top Plate). These Retainer Washers prevent loosening of their corresponding threaded fasteners."
10 CFR Part 50, Appendix B, Criterion V, requires that " activities affecting quality shall be prescribed by documented instructions, procedures, or drawings . . . and shall be accomplished in accordance with these instructions, procedures, or drawings." The failure to ensure that the locking tabs (retainer washers) were properly bent in accordance with Procedure SO23-411-57-12 was a violation of this requirement (Violation 361/98003-03). ;
The licensee determined that the bending of the locking tabs was a skill-of-the-craft expectation, in addition to correcting the deficiencies and reinspecting all the locking tabs, including Quality Control verification of the final conditions, the Nuclear l Construction Manager discussed performance expectations with the craft management ;
and with the craft, Nuclear Construction Engineering, and Quality Control personnel i involved. Also, the licensee proceduralized its previous expectation that before signing ,
for final acceptance of work, the Nuclear Construction Engineers are required to perform a final physicalinspection (walk down) of the work. The onsite MNSA vendor l representative rendered an opinion that the resulting loss of pre-load on the bolts, caused by the potential for the bolts or nuts to slightly rotate, would probably be insignificant, but recommended that the conditions be corrected to conform with the design. The licensee's actions were documented in AR 980201737.
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-14- Conclusions One violation of 10 CFR Part 50, Appendix B, Criterion V, was identified by the inspectors as the result of the licensee's failure to ensure that the locking tabs were
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properly bent on several nuts and bolts securing the MNSAs, indicating a weakness in
. the skill of the craft and in the attention to detail during quality control inspections. The licensee inadvertently over-drilled the counterbores on two holes on each of the two
pressurizer MNSAs, but the error was identified by the licensee during the inprocess quality control inspections. The over-drilling was partially the result of the licensee's intense focus on the most important parameter (total hole depth), that led to lesser focus
on the less-important parameter (counterbore depth). Other aspects of the MNSA l installations were in accordance with the design.
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E2.2 Failure of MSR Drain Line - Unit 2 Insoection Scoon (62707 and 37551)
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The inspectors reviewed the licensee's actions in responsa to the February 25,1998,
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failure of a drain line in the secondary plan Observations and Findinos On February 25,1998, while increasing reactor power after completion of the Unit 2 midcycle outage, the licensee identified a steam leak at the elbow of a 6-inch drain line from the east MS The licensee reduced reactor power to reduce the steam pressure in the drain line to near atmospheric pressure. Ultrasonic inspections of the failed area were performed, and the licensee determined that the failure was localized and was characteristic of erosion-corrosion. Six other similar elbows in Unit 2 were then inspected, with only minor wall thinning detecte .
J The licensee determined that the failed drain line was in its monitoring program, but that the inspection of the pipe was not due until the Cycle 13 outage. However, the licensee had plans for inspecting the failed drain line during the Cycle 10 outage, scheduled for early 1999. The licensee had calculated that the flow velocity in the pipe was about 5 fps, which was well below the FAC program guideline of 10 fp The drain line was not safety-related and was not subject to the ASME Code. However, it was within the scope of 10 CFR 50.65. The steam pressure in the drain line is l normally about 180 psig.
l The licensee performed a temporary (Furmanite) repair of the failed drain line, and
! planned to replace the elbow during the 1999 refueling outage. Additionaly, the I
licensee planned to examine the failed elbow after removal to better understand the failure mechanis ,
,'s-15-l The licensee decided to perform inspection of approximately 40 similar elbows in Unit 3 during the midcycle outage. At the exit meeting, the licensee informed the inspectors l
that nine elbows in Unit 3 were found to have substantial thinning due to FAC, although i all were above the minimum wall thickness. The licensee replaced the nine elbow Conclusions The licensee's response to a failed 6-inch MSR drain line was prompt and thoroug Engineering's preliminary assessment of the failure was rigorous.-
E7 Quality Assurance in Engineering Activities E Review of Licensee Enaineerina Assessments - Units 2 and 3 Insoection Scone (71750)
The inspectors reviewed the following engineering audits performed by the Nuclear Oversight Division: Audit 719-97, of Station Technical, completed December,1997; and Audit 722 97, of the Nuclear Fuels Management Group, completed in September,199 The inspectors reviewed the qualifications of the lead auditors for each of these audit The inspectors also reviewed the current status of selected open items from each of the audits, as well as the closure of selected items during the audits.
I Observations and Findinas
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The qualifications of the lead auditors met licensee programmatic requirements as stated in Procedure SO123-Xll-2.19, " Qualification and Certification of Auditing Personnel," Revision 2. In addition, one lead auditor was a registered quality enginee Based or. *eview of the qualifications of the lead auditors, the inspectors found the qualificatans satisfactory.
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The audit findrgs were both technical and administrative in nature, indicating a review of the technical aspects of engineering calculations and design changes, as opposed to
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a purely administrative audit. The open items reviewed were either appropriately l addressed by the audited organization or scheduled to be addressed. Of four open items reviewed, three remained open. The Station Technical audit had been completed for 3 months, with 'wo out of two open items still unresolved. The Nuclear Fuels audit
, had been completed for 6 months, with one out of two open items still unresolved. The l 6-month old open item involved disagreement between the audited organization and the auditors. In regards to both audits, the inspectors found that the corrective actions taken and planned were reasonable. Forecasts for completion of the open items were satisfactory, given the low significance of the items. The audited organization planned i to perform apparent cause assessments on two of the four items. These were l reasonable given the nature of the items. Consequently, root cause determinations ;
were being mad !
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l-16- Conclusions Two Nuclear Oversight Division audits of technical organizations were found to be effective in assessing performance.
IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 10 attention to REP - Unit 3 Insoection Scone (71750)
On February 19,1998, the inspectors walked down portions of the Unit 3 radiologically controlled are Observations and Findinas The inspectors observed five contract personnel cleaning and refurbishing SG testing equipment in the Unit 3 fuel handling area. The area was a contaminated radiation area. Two of the workers had their PEDS attached inside their protective clothing. The workers were performing their work using REP 200117-3, which required that the PEDS be wom outside of the protective clothing, unless otherwise directed by HP personne PEDS were wom outside the protective clothing so a worker could easily read the current dose. Also, the high dose and dose rate audible alarms would be more easily heard if the PED was outside the protective clothing. The inspectors informed HP personnel, who stopped the work and conducted training for the work group as to proper placement of the PEDS, as well as compliance with REPS. The workers had been given permission to attach the PEDS inside their protective clothing the previous day while lifting equipment, and while under HP supervision. However, the permission had been for the previous day onl Procedure SO123-Vil-20.11, " Access Control Program," Temporary Change Notice 3-1, Step 6.1.1, states that individuals will comply with requirements on REP j REP 200117-3 requires that PEDS be wom outside protective clothing, unless otherwise l directed by HP personnel. Procedure SO123-Vll-20.11 is applicable to Regulatory Guide 1.33, Revision 2, Appendix A. TS 5.5.1.1.a requires that those procedures applicable to Regulatory Guide 1.33 be implemented. This failure constitutes a violation of minor safety significance and is being treated as a noncited violation, consistent with Section IV of the NRC Enforcement Policy (NCV 362/98003-04). .; Conclusions
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Two of five contract workers were observed by the inspectors as not complying with !
their REP. The workers' PEDS were being worn inside their protective clothing while their REP required the PEDS to be worn outside their protective clothing. This resulted
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-17-in a noncited violation. In this instance, attention to the requirements of the REP was
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wea R1.2 EDG Fuel Oil Particulates - Unit 2 l Insoection Scooe (71750) l l
The inspectors monitored the licensee's actions as a result of a high particulate condition of EDG 2G003 fuel oi Observations and Findinas .
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On January 14,1998, the inspectors observed a start of EDG 2G003 from the diesel room. Shortly after the EDG start, local annunciation for high fuel filter differential '
- pressure alarmed. The inspectors questioned licensee personnel about the EDG filter alarm. In response to the inspectors' questioning, the system engineer reviewed the filter differential pressure history and discussed the trend with chemistry personne Chemistry personnel questioned the accuracy of previous onsite analysis results, and on February 5,1998, decided to split the first quarter 1998 sample and send it to an offsite i
laboratory for comparison with the on-site laboratory. On February 11, the licensee !
l received the fuel oil results from the offsite laboratory which indicated a particulate -
! l concentration of 31.9 mg/ liter and was above the TS 5.5.2.13.b limit of 10 mg/ liter. The
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onsite laboratory results indicated 0.0 mg/ liter. -
The licensee questioned the accuracy of the onsite lab and entered TS 3.8.3, Action D,
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which allowed 7 days to restore the fuel oil total particulates to within limits. The licensee had the fuel oil filtered, and confirmed by analysis on February 16 that the particulate level was reduced below the TS limit. The licensee initiated an investigation into the cause of the event. The inspectors will review the licensee's root cause and corrective actions during a future inspection (IFl 361/98003-05). l
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I l Conclusions An inspection followup item was identified to review the licensee's root cause and ;
corrective actions concerning the high particulate condition in the EDG fuel oi l l
[ S1 Conduct of Security and Safeguards Activities i S Unescorted Visitor in PA - Units 2 and 3 I Insoection Scoce (71750)
The inspectors observed security practices during a routine plant tour on February 16,1998, and observed a licensee employee with an " escort" badge but ,
without a visitor in his presenc l
. 'e r-18- Observations and Findinas l On February 16,1998, at approximately 4:45 a.m., the inspectors observed a licensee l Maintenance employee with an " escort" badge, but without a visitor, in the PA near a
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temporary diesel fuel oil filtering trailer. When challenged by the inspectors, the l Maintenance employee stated that the person he was escorting was inside the trailer.
L From where he was standing at the time, the employee could see the entrance to the l trailer. However, the employee had been checking temporary electrical connections l from the trailer inside a nearby building, and the entrance to the trailer could not be l directly seen from the entrance to the building. The inspectors determined that the employee did not have direct control over the visitor because he could not tell if the visitor had left the trailer. The inspectors determined that the visitor was still inside the traile Because of the diesel fuel filter process occurring inside the trailer, the visitor had the potential access to be able to sabotage the diesel fuel without being detected by the escort while the escort was not present. Security officers were posted at the fuel oil vault opening, about 50 feet from the trailer, as required. However, the filtering activities involved piping the fuel oil through temporary hoses and components in the trailer, and the Security officer could not see all these areas from the post locatio The inspectors informed the Security Manager of the situation, and the licensee initiated an investigatio The Physical Security Plan. Section 5.1.3, states that " visitors must be authorized escorted access by an approving authority designated in Station procedures, and must be escorted at all times within the PA by a card-key badged escort." Section 5.2. states that "all personnel who are not authorized unescorted access to the PA area are accompanied while in the PA by an individual who has been granted unescorted PA access and are limited to areas that they have a valid, work-related need to enter." This section also requires that the escort be "able to maintain visual observation in order to detect any unauthorized activities."
The licensee's corrective actions including coaching the escort, briefing Maintenance personnel associated with the filtering operation regarding the issue, and highlighting the escort requirements in a weekly Maintenance newsletter that was discussed with all Maintenance personne The failure to maintain visual observation of the visitor by a key-card badged escort was a violation of the Physical Security Plan. Section 5.2.1.1 (Violation 50-361/98003-06). Conclusions A Maintenance technician failed to maintain visual observation of a contractor working in the PA, which was a violation of the Physical Security Plan requirements for escorting visitor . *~e l
l' -19-i' S1.2 Classification of Temocrary Diesel Fuel Oil Filtration System - Unit 2 l Insoection Scone (71750)
The inspectors inspected the security measures implemented for the temporary equipment associated with filtering the EDG fuel storage tanks in Unit 2 during February 199 Observations and Findinas On February 19,1998, the inspectors observed that the EDG fuel storage vault was breeched and that the fuel storage system was temporarily extended above ground for about 100 feet by means of 4-inch diameter hoses. The fuel was being pumped from l the storage tanks, through filters in a temporary trailer, then about 50 feet to an open l
vault containing fuel transfer system components, which directed the fuel back to the '
storage tanks. All the above-ground temporary equipment was outside the vital area, in the PA. The EDGs were considered operable during the filtration system operatio A Security officer was posted at the open vault. However, the officer was directed only to protect the vault. The vault was covered by a tent. From where the officer was posted, permanent and temporary structures prevented the officer from being able to observe very much of the exposed hoses and filtration equipment. Tents also covered the storage tank vaults. The vaults were closed, and the hoses were attached to the tank vents. These were not visible to the posted Security office Table 4-4 of the Physical Security Plan lists the Unit 2 diesel generator building and fuel storage area as a vital are The inspectors notified Security management that the temporary system could be vital equipment requiring appropriate compensatory measures. After an initial review of the circumstanced, the licensee made a 1-hour notification to the NRC in accordance with
- 10 CFR 73.71 and 10 CFR Part 73 Appendix G (Log Number 33753).
This matter is considered unresolved pending the NRC's review of the licensee's final l
determination of the appropriate security classification of the temporary system while in l
, operation. The licensee is documenting its review in AR 980202114 (Unresolved item 361/98003-07). Conclusions An unresolved item was identified regarding the appropriate security classification of the temporary equipment used for filtering the EDG fuel oi :
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. * a-20-S8 Miscellaneous Security and Safeguards issues (92904)
S8.1 (Closed) Violation 361: 362/97019-05: seismic tractor not secured. The inspectors verified the corrective actions described in the licensee's response letter dated November 7,1997, to be acceptable and complete. No similar problems were identifie V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the exit meeting on March 18,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie . ,
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e o ATTACHMENT SUPPLEMENTAL INFORMATION l
PARTIAL LIST OF PERSONS CONTACTED l
Licensee l
C. Anderson, Manager, Site Emergency Preparedness M. Herschthal, Manager, Station Technical (Acting)
l J. Clark, Manager, Chemistry l J. Fee, Manager, Maintenance G. Gibson, Manager, Compliance D. Herbst, Manager, Site Quality Assurance
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J. Madigan, Manager, Health Physics (Acting) '
R. Krieger, Vice President, Nuclear Generation D. Nunn, Vice President, Engineering and Technical Services T. Vogt, Plant Superintendent, Units 2 and 3 R. Waldo, Manager, Operations 1
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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 92904: Followup - Plant Support ITEMS OPENED AND CLOSED Opened 361; 362/97019-05 VIO seismic tractor not secured 361/98003-01 NCV 4160 V breaker operation 362/98003-02 NCV AFW pump room valve test 361/98003-03 VIO MNSA locking tabs improperly bent 362/98003-04 NCV improper wearing of PEDS !
361/98003-05 IFl EDG fuel oil particulates 361; 362/98003-06 VIO unescorted visitor in PA 361/98003-07 URI security classification of temporary diesel fuel oil filtration system
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o I 1-2-Closed 361; 362/97019-05 VIO seismic tractor not secured 361/98003-01 NCV 4100 V breaker operation
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362/98003-02 NCV AFW pump room valve test 361/98003-03 VIO MNSA locking tabs improperly bent i 362/98003-04 NCV improper wearing of PEDS 361; 362/98003-06 VIO unescorted visitor in PA l LIST OF ACRONYMS USED AFW auxiliary feedwater L
AR action request CEA control element assembly CO control operator CRS control room supervisor EDG- emergency diesel generator EDMR equipment deficiency mode restraints EP emergency preparedness FAC flow-accelerated corrosion
, HJTC heated Junction thermocouple -
l HP health physics i MNSA mechanical nozzle seal assembly i MSR moisture separator reheater NCR nonconformance report NPEO nuclear plant equipment operator i i PA protected area l PDR Public Document Room PED portable electronic dosimeter
- RCS REP reactor coolant system radiological exposure permit RTCB reactor trip circuit breaker SG steam generator )
l SS shift superintendent L SWC saltwater cooling TS Technical Specifications l i
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