IR 05000361/1997023
| ML20199H494 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 11/19/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20199H475 | List: |
| References | |
| 50-361-97-23, 50-362-97-23, NUDOCS 9711260132 | |
| Download: ML20199H494 (22) | |
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ENCLOSURE
. U.S. NUCLEAR REGULATdRY COMMISSION'
REGION IV
Docket Nos.: 50-361 50-362 '
License Nos.: NPF 10 NPF 15 Report No.: 50-361/97 23 50 362/97-23 Licensee: Southern California Edison C Facility: San Onofre Nuclear Generating Station, Units 2 and 3 Location: 5000 S. Pacific Coast Hw San Clemente, California
- Dates:- September 28 through November 8,1997 inspectors: J. Sloan, Senior Resident inspector J. Russell, Resident Inspector J. Kramer, Resident inspector -
Approved By: Dennis F. Kirsch, Chbf, Branch F Division of Reactor Projects
~ ATTACHMENT: . . Supplemental linformation
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EXECUTIVE SUNiMM San Onofre Nuclear Generating Station, Units 2 and 3 NRC Inspection Report 50 361/97 23; 50-362/97-23 This routine, announced inspection included a>pects of licensee operations, maintenance, engineering, and plant support. This report covers a 6-week period of resident inspectio Ooerations
- Control room operators performed satisfactorily while shifting letdown flow control valves from Valve FCV01108 to Valve FCV0110A and oversight provided by the control room supervisor was excellent. A communications weakness, during a concurrent surveillance test, between Maintenance and the operating crew resulted in Operations not expecting an annunciation for containment hydrogen levels, which distracted the control operator during the evolution (Section 01.1).
- The operating crew authorized the performance of a surveillance on radiation monitors which, while allowable under hcense conditions, degraded the ability to diagnose the affected steam generator during a tube rupture event. This demonstrated a weak operator attention to detail regarding the overall status of radiation monitonng instrumentation (Section 01.2).
- Control room operators demonstrated weakness in knowledge and skill of the craf t in attempting to close the emergency diesel generator (EDG) output breaker while a voltage mismatch automatically prohibited breaker closura (Secte 04.1).
- An operating crew demonstrated satisf actory performance during a requalification scenario examination. However, timeliness of completion of the standard posttrip actions, as well as performance while using DC-powered components to feed steam generators, was weak. Licensee instructor evaluation, and subsequent corrective actions, were strong (Section 05.1).
- Operato s did not aggressively pursue the resolution and correction of an adverse condition that had repeatedly caused a rapid fouling of a component cooling water (CCW) heat exchanger. Statior. Technical, when made aware of the =ituation by the inspectors, aggressively established and corrected the cause of the fouling (Section E2.1).
Maintenance
- Generally, the inspectors found that good material conditions were being maintained; although isolated problem examples were identified, which indicated that plant personnel needed to improve their level of attention to detail during their
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-3-I walkdowns. The licensee's response to the inspectors' observations was good (Section M2.1).
- The licensee refurbished the Unit 3 charging pump rooms and significantly improved the material condition and appearance of the pumps and pump rooms. The refurbishment improved the accessibility around the pumps (Section M2.2).
- The chemical and volume control system (CVCS) procedure for filter chareging provided clear and thorough instructions to craft personnel for changing out the CVCS purification filter (Section M3.1).
- The instrumentation and control (l&C) technicians demonstrated c knowledge weakness by calibrating the EDG day tar 8 levelinstrument using an undesirable method that resulted in an unknown inaccuracy of the instrument, l&C supervision recognized the calibration deficiency and corrected the problem prior to returning the component to service (Section M4.1).
Enoineerino
- Station Technical performed a detailed investigation into the cause of the CCW heat exchanger fouling and develooed good corrective actions to help prevent future occurrence (Section E2.1).
Plant Sucoort
Generally, the inspectors observed good radiological conditions during routine plant tours; although, some isciated conditions needing improvement were identified. For example, three areas of loose surface contamination were observed which were not previously identified by the licensee. The inspectors concluded that licensee personnel conducting plant tours needed tc improve their attention to detail in identifying and posting areas of loose surface contamination (Section R1.1).
A Health Physics (HP) technician provided excellent HP coverage for the mechr'ics and observers during the spent fuel pool gate repairs (Section R4.1).
- HP supervision did not aggressively correct a previous licensee identified condition where water had crossed a contaminated boundary until the situation was found by the inspectors (Section R4.2).
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Report Detailt
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Summary of Plant Status -
Units 2 and 3 operated at essentially 100 percent power during this inspection period, l. Onerations 01 Conduct of Operations 01.1 Shiftina Reactor Coolant System Letdown Flow Control Valves - Unit 2 Insoection Scone (71707)
The inspectors observed Unit 2 control room operators remuve reactor coolant system letdown flow Control Valve FCV0110B from service and placing Valve FCVP110A in service. The inspectors reviewed Procedure SO23-3 2.1,
"CVCS Charging and Letdown," Revision 16, which was used to perform the evolutio Observations and Findinos On October 14,1997, control room operators removed Valve FCV0110B from service in order to perform maintenance. During the evolution, Charging Pump 2P190, in standby, automatically started and stopped twice due to fluctuations in pressurizer level. This was due to erratic operation of Valve FCV0110A when it was operated in parallel with Valve FCV0110B during the switch over, and when placed in servic During the evolution, an authorized monthly surveillance was being performed on the Train B loss of coolant post accident hydrogen monitor. The surveillance caused annunciation for containment hydrogen levels, some of which were expected, and soma that the control operator considered unexpected. The annunciation distracted the control operator at times, while coordinating with the assistant control operator, from performing the evolution. The annunciation was normal for the surveillance; however, incomplete communication from Maintenance personnel performing the surveillance resulted in the control operator being unaware that the particular annunciator would be actuate Unit 2 operation with Valve FCV0110A continued to be erratic, with the pressurizer level slowly decreasing with one charging pump operating. Valve FCV0110A controller settings and valve performance were unable to provide letdown flow compatible with one charging pump. The uperators started a second charging pump
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until Valve FCV0110A could be removed from se_ / ice and Valve FCV01108 could be placed in service again. The erratic operation of the letdown flow control valves was being addressed by Station Technical and Maintenanc .
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\. Conclusions Control room operators performed satisf actorily while shifting letdown flow control valves from Valve FCV0110B to Valve FCV0110A and. oversight by the control room supervisor was excellent. A communications weakness, during a concurrent surveillance test, between Maintenance and the operating crew resulted in Operations not expecting an annunciation for containment hydrogen levels, which distracted the control operator during the evolutio .2 Badiation Monitorina instrumentation - Unit 3 Insoection Scone (71707)
The inspectors walked down the Unit 3 control boards and observed that certain steam generator and condenser offgas radiation monitors were inoperable. The inspectors discussed the observation with Operations managemen Observations and Findinas On October 15,1997, th.s inspectors walked down the Unit 3 control boards and observed that C+aam Gr,nerator E089 main steam line Radiation Monitor RM7874, Steam Generator EGd9 blowdown Radiation Monitor RM6753, and one of two condenser offgas radiation monitors, RM7818, were inoperable. Appropriate compensatory measures were in effect in accordance with license requirements; however, the inspectors were concerned because this condition degraded the licensee's ability to diagnose the affected steam generator during a tube rupture event. The blowdown radiation monitor was out of service for decontamination, the main steam line radiation monitor was inoperable for a monthly surveillance, and the condenser offgas monitor was out of service for a design chang Secondary radiation monitors in alarm would cause a diagnosis of steam generator tube rupture in accordance with the emergency operating instructions. However, identification of the affected steam generator depended on operator comparison of radiation monitor indications for each generator. With blowdown and mainstream line radiatir, monitors inoperable on one steam generator, elevations in these levels would not be apparent without direct sampling Consequently, the diagnosis would be made based on either sampling or a lack of elevated readings in the intact steam generator. This could delay the isolation of the affected steam generator and decrease the reliability of the diagnosis because the redundancy of indications was decreased, in response to the inspectors' concern, Operations management generated Action Request 971000847 to clarify expectations for radiation monitor availabilit _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ ___
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! Conclusions The operating crew authorized the performance of a surveillance on radiation monitors which, while allowable under lwense conditions, degraded the ability tc diagnose the affected steam generator during a tube rupture event. This demonstrated a weak operator attention to detail regard:ng the overall status of radiation monitoring instrumentatio O3 Operations Procedures and Documentation 03.1 Acolicability of Instrumentation to EDG Technical Soecification (TS) - Unit 2 Insoection Scone (717Q21 On October 20,1997, the reactor vessellevel monitoring portion of Unit 2 Qualified Safety Parameter Display System (OSPDS) Train A failed and was declared inoperable. Reactor vessellevel monitoring is a TS-required postaccident monitoring instrument (PAMI), and the licensee entered TS 3.3.11 for one train inoperable. On October 21,1997, at 2:40 a.m., EDG 2G003 (the Train B diesel) was declared inoperable for scheduled maintenance. Around 9 a.m. on October 21,1997, the inspectors questioned Unit 2 licensed operators in the control room about the operability of OSPDS Train B. The inspectors reviewed unit logs for October 20-21, 1997, limiting condition for operation action required sheets, and interviewed operators and managers, Observations and Findinas Unit 2 TS 3.8.1.B.2 requires, in part, that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of declaring an EDG inoperable, those features powered from the same train as the inoperable diesel, with equivalent opposite train features inoperable, must be declared inoperable and the appropriate action statements entered. If this is not done, then the unit must be placed in Mode 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Based on the inspectors' questions, the licensee declared OSPDS Train B inoperable on October 21,1997. The inspectors were informed by the shift technical advisor, who had talked with the unit operating crew, that this was done at 1 p.m. on October 21,1997. The Licensing manager later informed the inspectors that the actual intporable declaration time was around 10 a.m. The limiting condition for operation action request sheet recorded 2:40 a.m. as the inoperable declaration time. The unit logs did not show any entry for the time of inoperability, and only showed QSPDS inoperable on the October 22, 1^47, midnight status entr Although the licensee maintained QSPDS inoperable for as long as EDG 2G003 was inoperable, at the end of this inspection period the licensee was planning a change to the bases of TS 3.8.1.B.2. If an event occurred'with a loss of offsite power and an inoperable EDG, the inspectors observed that the PAMI instrumentation on the
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I same train as the inoperable EDG would be powered from the station batteries for a couple of hours; however, they would not be available for use by operetors after the batteries had been depleted. OSPDS was used for reactor vessellevel monitoring, which was used to verify natural circulation, and consequently the core heat removal safety function, was satisfied. This item is open pending the inspectors'
review of the TS bases revision (Inspector Followup Item 361/97023-01), Conclusions An inspector followup item was opened to deter.1ine applicability of PAMI to TS Action 3.8.1. Operator Knowledge end Performance 04.1 EDG Voltaae - UchJ Insoection Scoce (71707)
On October 14,1997, the inspectors observed Unit 3 operators synchronizing EDG 3G002 to the grid during performance of Surveillance Procedure SO23-3 3.23,
" Diesel Generator Monthly Test," Revision 12. The inspectors reviewed Procedure SO23-3 3.43.16, "ESF Subgroup Relay K-401 A Semiannual Test,"
Revision 3, and Procedure SO23-213, " Diesel Generator Operation," Revision 1 The inspectors also interviewed operations shift personnel, including senior reactor operators and reactor operators, Observations and Findinas Units 2 and 3 have synchronizing monitoring circuits installed that prevent closing the EDG output breaker when voltage between the EDG and the 4.16 kV safety-related bus are not within 3 percent. The inspectors observed that the first attempt operators made to close the EDG 3G002 breaker was with the EDG output voltage at 4.49 kV, and bus voltage at 4.35 kV, This created a 140 volt mismatch between the voltages and was greater than the 3 percent allowable. The operators first attempt to close the EDG breaker was unsuccessful due to this mismatch. The operators then lowered the EDG output voltage to within the 3 percent of the 4.16 kV bus and successfully closeo the breake Attempting to close the EDG output breakers with voltage not sufficiently matched was previously documented in NRC Inspection Report 50-361;362/96-11. At that time, the licensee planned on making the operators more aware of the 3 percent criteria for voltage. The inspectors interviewed various operators and found that they were aware that there was an automatic interlock to prohibit EDG output breaker closure, but were not consistently aware of the exact voltage deviation percentage and genera..y assumed that preset voltage on the EDG wodd be within
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the 3 giercent. The 3 percent was stated in page 181 of Procedure SO23 2-13, but was not stated in the monthly or semiannual surveillance procedures. Procedurally, operators were directed to match voltage, and il the synchronization was not successful, an option was to check status lights'outside the control room to sets if the automatic prohibit was in effect. The inspectors found that operators had followed procedure, but that knowledge and skill of the craft was weak in this instanc In response, Operations management generated a Priority 2 reading for operators, which stipulated the 3 percent requirement and the use of digital voltage indication, and noted that, in most cases, it would be necessary to lower the EDG voltage from preset value in order to successfully parallel. In addition, Operations management directed the shif t superintendents to personally oversee the next several months of EDG parallel operations to ensure voltages are matched. The inspectors found that these actions adequately addressed the concern, Conclusions Control room operators demonstrated weakness in knowledge and skill of the craft in attempting to close the EDG output breakers while a voltage mismatch automatically prohibited breaker closur Operator Training and Qualification 05.1 Simulator Reaualification Exam - Units 2 and 3 insoection Scone (71707)
The inspectors observed a licensee-evaluated scenario in the simulator that was conducted for a licensed operator requalification exarnination, in addition, the inspectors reviewed the licensee simulator instructors' evaluation of the scenari Observations and Findinos On October 16,1997, the inspectors observed a scenario that included a steam generator tube rupture in Steam Generator E089, concurrent with a f ault (a stuck open safety valve)in Steam Generator E088. The crew accomplished all critical tasks and successfully mitigated the casualty. The inspectors cbserved, however, that the operating crew took approximately 22 minutes to complete standard posttrip actions, which was considered to be an excessive amount of time. Based on previous discussions with Operations management, the inspectors found that the expectation for completing these actions was approximately 1D minute Consequently, diagnosis and mitigation of the tube rupture was delayed. Also, the inspectors observed that the crew, when faced with only the turbine-driven auxiliary feedwater pump and DC-powered valves available to feed steam generators, failed
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6-I to initiate auxiliary feedwater from the control room using this DC-powered equipment. The crew had dispatched operators to operate the valves locally, although DC power had been available to operate the valves from the control roo The inspectors reviewed a licensee simulator instructors' evaluation of the scenario performance dated October 16,1997, and observed that both of the issues mentioned above had also been observed by the instructors. The crew passed the
= wonario portion of the requalification examination, but was assigned additional remediat)on.- The instructors' evaluation was critical and evidenced good instructor attention to_overall crew perfarmance and attention to the details of the performance, Conclusions An operating crew demonstrated satisfactory perfortnance during a regaalification scenario examination. However, timeliness of completion of the standard post trip actions, as well as performance while using DC-powered components to feed steam
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generators, were weak. The licensee instructor evaluation, and subsequent corrective action', were stron Miscellaneous Operations issues (92901)
08.1 (Closed) Viplatipn 361/97017-02: power ascension with failed fuel pi This violation occurred when the licensee increased reactor power at a rate exceeding the procedural limits when fuel cladding defects were known to exis While a deliberato decision had been made to increase power at 10 percent per hour, instead of at the procedurallimit of 5 percent per hour, miscommunications between senior management end control room operators resulted in the power being increased at approximately 14 percent per hour, and the procedure not being revised to allow the higher ramp rat The licensee's corrective actions addressed the communications deficiencies snd confirmed that the fuel cladding leak had not been aggravated by the higher ramp rate. These corrective actions were acceptabl .2 . (Closed) Violation 361/97017-03: volumo control tank (VCT) inlet diversion valve in incorrect mod This violation occurred when operators failed to place the letdown divert Valve 2LV0227A'in manual when the downstream manual block valve was closed l due to leakage past Valve 2LVO227A, contrary to procedural requirements. The -
licensee's corrective actions included counseling the individuals involved and briefing all Operations crews. The licensee also revised the procedure to delete the requirement for placing the letdown divert valve in manual when the block valve l
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-7-I was closed. Instead, the procedure was revised to state that the letdown divert valve should be placed in manual when the block valve is to be closed for extended periods of time. While placing the divert valve in manual when the block valve is closed is a good operating practice to prevent inadvertent lifting of reliefs or isolation of the letdown system, operators do not normally rely on the automatic cycling of Valve 2LV0227A to control VCT level, and the procedural change presents very httle additional risk of these consequences. The inspectors considered . i corrective actions acceptabl .3 (Closed) Insoection Followuo item 361:362/96015-02: Updated Final Safety Analysis (UFSAR) discrepanc This item involved inspector identifice tion of an instance in which the UFSAR was not accurate. The UFSAR description of VCT operation was misleaoing in that it stated that VCT level was maintained by the automatic system in f act, however, during normal steady state operations, operators manually controlled VCT level. The inspectors reviewed UFSAR Change Request SAR 23 543, and determined that it was sufficient to correct the inaccuracy in the UFSAR with regards to VCT operation. The inspectors also found that this change to the UFSAR did not represent an unreviewed safety question, 11. Maintenance M1 Conduct of Maintenance M 1.1 General Comments Insocction Scoce (62707)
The inspectors observed all or portions of the following work activities:
- Sample boric acid makeup Pump 2MP174 oil (Unit 2)
- High pressure safety injection Pump 2P019 Breaker 2A0618 relaying and metering preventive maintenance (Unit 2)
- Containment nigh range radiation Monitor 3Rl7820 troubleshooting (Unit 3)
Perform impeller lift of saltwater cooling (SWC) Pump 3P112 (Unit 3) Observations and Findinas The inspectors found the work performed under th i activities to be thorough. All work observed was performed with the work package present and in active us Technicians were knowledgeable and professional. The inspectors frequently
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observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applict vie, appropriate radiation controls were in plac M1.2 General Comments on Surveillance Activities a.- Insoection Scoce (61726)
The inspectors observed all or portions of the following surveillance activities:
- EDG Fuel Oil Storage Tank Water Accumulation Surveillance (Units 2 and 3)
CREACUS Test (Units 2 and 3)
EDG 3 GOO 2 Semiannual Test (Unit 3)
- Engineered Safety Features Subgroup Relay K-401 A Semiannual Test (Unit 3) Observations and Findinas The inspectors found all surveillances performed under these activities to be thorough. '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 surveillance observed under Section M M2 Maintenance and Material Condition of Facilities and Equipment
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M 2.1 Review of Material Condition Durina Plant Tours
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During the inspection period, the inspectors conducted routine plant tours and evaluated plant material condition, Observations and Findina Generally, the inspectors found that good plant material condition was being i maintained; although some isolated examples of needed improvement were identified.
L On October 1,1997, the access cover for fuel handling building postaccident cleanup Unit 3ME370 was slid open approximately 4 inches. The licensee j determined that only the access cover was slid open, and that the actual ducting
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I was intact. The licensee closed the access cover and replaced the lost screw that held the cover shu On October 1,1997, Unit 3 hi h0 pressure safety injection to Hot Leg 1 Isolation Valve 3HV9434 had grease leaking out of the actuator. The licensee initiated an action request to havs the actuator repaired and performed an operability assessment that concluded that the valve was operabl On October 1,1997, the inspectors noted that the Unit 3 30-foot penetration Room 209 had excessive condensation accumulation on the floor inside a contaminated area. The licensee installed r metal drip pan on the floor to catch and control the spread of wate On October 30,1997, the inspectors identified lighting deficiencies in the Unit 3 CCW pump rooms and penetration areas. The licensee performed walkdowns of the areas to evaluate the need for replacement bulbs, Conclusions Generally, the inspectors found that good material conditions were being maintained; although isolated examples were identified, which indicated plant personnel needed to improve their level of attention to detail during their walkdowns. The licensee response to the inspectors' observations was goo M2.2 Charoino Pumos Room Preservation - Unit 3 (62707)
The licensee recently refurbished the Unit 3 charging pump rooms, including repainting the entire room and the pump components. The inspector observed that a posted contamination area had been substantially reduced in size around Pump 3P191, and that the posted contamination areas around Pumps 3P190 and 3P192 had essentially been eliminated. Additionally, there was no evidence of oil leaks around Pumps 3P190 and 3P192, as had been routinely observed in the past. The inspector concluded that the licensee had significantly improved the accessibility around the pumps and had improved the material condition and appearance of the pumps and pump room M3 Maintenance Procedures and Documentation M3.1 CVCS Purification Filter Chanaeout Procedure Review insoectica Scoce (62707)
The inspectors reviewed Maintenance Procedure S023-I-6.128, "CVCS Purification Filter Changeout," Temporary Change Notice O-3, dated October 25,199 ____________
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} Observations and Findinos Procedure SO2316.128 provided detailed instructions for changing out the CVCS purification Filter F020. The filter may be highly radioactive (according to the procedure, up to 2000 R/hr), and is enclosed.within a filter housing in a normally inaccessible vault. The filter is accessible through relatively small openings in the floor of the room above, and requires the use of special long-handled tools to be safely remove The procedure included sketches of the special tools required for the task and the arrangements for their use. Both general and specifin instructions were provided regarding when and how to use the tools to prevent inadvertent dropping of the grapple toolinto the filter vault, Conclusions Maintenance Procedure S023-I-6.128 provided clear and thorough instructions to craft personnel for changing out the CVCS purification filte M4 Maintenance Staff Knowledge and Performance M4.1 EDG Dav Tank Level Calibration - Unit 2 insoection Scone (61726)
The inspectors observed I&C technicians perform an instrument calibration and discussed the technicians' performance with the l&C supervisor of plant maintenance (SPM). Observations and Findings On October 21,1997, the inspectors observed l&C technicians perform a calibration of EDG 2G003 day tank level auto fill stop Interlock 2LCH5933-2. The instrument was a Magnetrol liquid level switch that consisted of three cylindrical floats. The inspectors observed the technicians place the level switch in a float column to calibrate the instrument. During the calibration process, one of the floats was suspended in water and the other two in fuel oil. The inspectors questioned the accuracy of performing the calibration with one of the floats in water. The technicians indicated that the as-left setpoint of the instrument would be off slightly, but still within the accuracy of the instrument. The technicians stated that they did not know the exact value that the instrument would be inaccurate, and subsequently completed the calibratio _ _ _ _ _ - _ - - _ _ _ _ - -
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The inspectors discussed the observation with the l&C SPM. The SPM indicated that the technicians did not use a desirable method to calibrate the instrument and would follow up the issue, in addition, the SPM indicated that the Magnetrol instrument calibration was a " skill of the craft" evolution and, therefore, detailed procedure guidance was not included in the maintenance order. Subsequently, the SPM informed the inspectors that the first line supervisor overseeing several jobs being performed on the EDG also recognized the inappropriate method used by the technicians to calibrate the instrument and directed the technicians to reperform the calibiation with all of the floats in fuel oil. The licensee planned to add a statement on the instrument calibration data cards to indicate that the preferred method to calibrate the instrument is in fuel oil to avoid correction factors due to specific gravity differences, Conclusions The l&C technicians demonstrated a knowledge weakness by calibrating the EDG day tank level instrument using an undesirable method that resulted in an unknown inaccuracy of the instrument. However, l&C supervision recogn! zed the calibration deficiency and corrected the problem prior to returning the component to servic M8 Miscellaneous Maintenance issues (92712,92902)
M 8.1 (Closedl Licensee Event Reoort (LER) 361/97-007-01: missed surveillance test for the containment purge exhaust radiation monitor On July 18,1997, the licer see submitted a revised LER to document the results of further review of the missed surveillance test for the containment purge exhaust radiation monitors between January 23,1989, and January 12,1990. The licensee concluded that the previously reported overlapping testing did not verify operation of the radiation monitor solenoid valves (2HY9821 A in Figure 1 of the LER) and, therefore, was not an overlapping test, in addition, the RT7828 radiation monitors do not have a downscale failure alarm, so that the surveillance requirement to verify automatic isolation upon a downscale failure was not being performe The licensee determined that additional radiation monitors listed in Table 1 of the LER had been required in the past by TSs to be surveilled for downscale failure, but could not be surveilled as required because they did not have downscale failure alarms. The licensee concluded that the missed TS surveillance requirement was reportable and included that in the revised LER. The licensee noted that the LER Table 1 monitors had been either relocated to the offsite dose calculation manual or otherwise eliminated from TS The licensee concluded (as in the original LER) that improvements made subsequent to the 1989 event strengthened the process for revising surveillance test procedures to the extent that further program enhancements were not require a$ \
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The inspectors concluded that the licensee's corrective actions were acceptable and further enforcement action was not warranted since the initial LER wcs dispositioned as a noncited violation in NRC Inspection Report 50 361;362/97-1 M8.2 (Closed) Insoection Followuo item 361: 362/97019-02: painting inside the control room envelop This item was created to review a licensee analysis of painting within the control room emergency air cleanup system (CREACUS) boundary. The analysis was performed to demonstrate that the paint fumes would not commrnicate with CREACUS charcoal through veritilation ducting. The ducting provided a path for air flow from the spaces being painted to the CREACUS units. TSs require that a charcoal sample be analyzed if " communication" of the volatile organic compounds in the paint fumes existed between the spaces being painted and the CREACUS units. The licensee had not historically taken charcoal samples unless some type of forced flow of air from the space being painted to the CREACUS unit existe The licensee's historical summary of painting showed the following amounts of paint were used: 1988, 7 gallons; 1990,10.5 gallons; 1991, 2.6 gallons; 1993, 1.5 gallons; and 1994,1.1 gallons. For the current control room refurbishment a total of 11.9 gallons of paint were planned to be used. Samples of CREACUS charcoal taken about every 18 months showed charcoal efficiency was not affected by the gallons of paint listed above. Since the 11.9 gallons currently being used was roughly equivalent to the amounts used previously, the inspectors found that the CREACUS charcoal would not degrade in efficiency solely due to the current painting. Consequently, the inspectors concluded that there was no substantial " communication" through the ventilation ducting without forced flow, and no charcoal sample was require Ill. Enoineerina E2 Engineering Support of Facilities and Equipment E CCW Heat Exchancer Foulino Insoection Scoce (37551)
The inspectors discussed a higher than normal CCW heat exchanger fouling rate with the operators, and then inquired about the fouling with Station Technical, Observations and Findinos On August 26,1997, the inspectors observed the Unit 3 ooerators perform a back flush of a CCW heat exchanger and discussed the evolution with the operator . . -- -- .- . -
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During the discussion, the operators indicated that a salt water cooling (SWC) pump was recently started and the CCW heat exchanger fouled quickl On August 28, the inspectors informed Station Technical about the abnormal fouling - 1
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abnormal rate of fouling of the Unit 3 CCW heat exchanger. The inspectors were '
concerned that should an event occur during which the one normally operating CCW ,
train failed and the idle second CCW train started and rapidly fouled, the CCW heat exchanger and SWC (ultimate heat sink) would not perform their designed safety function *
Station Technical reviewed the trends of Units 2 and 3 CCW heat exchangers over the past 3 years and noted that in 8 instances the CCW heat exchangers experienced a rate of differential pressure increase (fouling) that was not norma Station Technical concluded that the commonality among the incidents was that the
. SWC piping was not being maintained in an optimal condition and the worst cases l were related to postoutage heat treating of the SWC piping.
l- The licensee concluded that the root cause of the fouling of the CCW heat
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exchangers was caused by the following sequence of events. First, a buildup of marine life (shells) occurs in the SWC piping. Second, the marine life is killed or l weakened by the heat treat process, draining of the system, or placing the SWC
- train in standby (uepleting the food and oxygen supply). Finally, the system is shocked through pump starts and the marine life is removed from the piping and
, fouls the CCW heat exchanger. The licensee concluded that the CCW heat l_ exchangers were not being clogged with material being drawn into the system by
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the SWC pumps, but rather shells growing in the SWC piping, since the operating SWC train did not experience the abnormal foulin The licensee planned to perform several corrective actions as a result of the fouling issue. The cognizant engineer will coordinate the routine SWC heat treat plans to -
ensure the appropriate SWC trains are being heat treated. Operations will ensure that before a SWC train is placed in standby a backflush will be performed to reduce the CCW heat exchanger differential pressure (if the pressure is high). Following an
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outage, Operations and the cognizant engineer will closely plan and monitor the
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operation, backflushes, and heat treats of the SWC system through power ascensio . . Conclusions
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Operators did not aggressively pursue the resolution and correction of an adverse l
condition that had repeatedly caused a rapid fouling of a CCW heat exchanger.
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Station Technical performed a detailed investigation,into the cause of the CCW heat exchanger fouling and developed good corrective actions to help prevent future occurrence.
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E8 Miscellaneous Engineering issues (92712,92903)
E (Closed) LER 361/97004-00: reactor coolant system leakage - pressurizer thermowell This voluntary LER addressed reactor coolant system pressurizer boundary leakage as the result of Inconel 600 nozzle cracking. This issue was addressed in NRC Inspection Reports 50 361;362/97-05 and 50 361; 362/97-1 E8.2 (Closed) LER 362/97001-00: reactor coolant system leakage - instrument thermowell nozzle (Closed) LER 362/97002-00: reactor coolant system leakage - instrument thermowell nozzle These voluntary LERs addressed reactor coolant system pressurizer boundary leakage as the result of Inconel 600 nozzle cracking. The issues were addressed in NRC Inspection Reports 50-361; 362/97-09 and 50-361; 362/97-1 E8.3 IClosed) Violation 361: 362/97012-05: failure to submit an LER within 30 day The inspectors verified the corrective actions described in the licensee's response letter, dated August 15,1997, to be sufficient and complete. No similar problems were identifie IV Plant Sunoort
R1 Radiological Protection and Chemistry Controls
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R1.1 Unoosted Loose Surface Contamination - Units 2 and 3
. insoection Scone (71750)
-_The inspectors performed routine plant tours and identified several unposted loose contamination areas and discussed the observations with the HP manager.
+ Observations and Findings Generally, the inspectors observed good radiological conditions during routine plant tours. However, the inspectors identified some isolated unposted loose surface ,
contamination areas:
- On October 8,1997,' the inspectors identified a boric acid build up on Unit 3 containment spray Train B flow Transmitter 3FT0348-2 and informed H An HP technician surveyed the area and found 8,000 disintegrations per minute (dpm) of activit .
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- On October 22,1997, the inspectors identified a boric acid build up on Unit 2 high pressure safety injection Pump 2P-018 discharge stop check Valve S21204MUO16 and informed HP, An HP technician surveyed the area and found 10,000 dpm of activit * On Octobcr 30,1997, the inspectors identified a boric acid build up on Unit 3 charging Pump 3P191 discharge pressure safetv/ relief Valve 3PSV9226 and informed HF. An HP technician surveyed the area and found 2,000 dpm of activit The licensee initiated action requests to address the boric acid build up and performed operability assessments of the components when warranted. HP posted the contaminated areas and installed the necessary drip catche The inspecturs discussed the unposted contamination areas with the HP manage The HP manager indicated that the contamination identified on October 22 resulted from the pressurization of the system during an Inservice test. The routine surveys of that area were not due and, therefore, did not identify the contamination. The HP manager indicated that the licensee planned to incorporate, through the action request system, that whenever a potentially contaminated system is pressurized a field support assignment to HP will be generated to walk down the system and check for contamination, in addition, whenever station techtiical or the boric acid leak team identifies wet or dry boric acid un action request is generated. To ensure HP awareness of the boric acid leak, the action request committee will create a field support assignment to HP to survey and post (if corqaminated) the area, Conclusions Generally, the inspectors observed good radiological conditions during routine plant tours; although, some isolated conditions needing improvement were identified. For example, three areas of loose surface contamination were identified which were not previously identified by the licensee. The inspectors concluded that licensee personnel conducting plant tours needed to improve their attention to detail in identifying and posting areas of loose surface contaminatio R4 Staff Knowledge and Performance in Radiological Protection and Controls R4.1 HP Technician Suonort of Maintenance - Unit 3(71750)
On September 29,1997, the inspectors observed HP technician support of corrective maintenance performed on the gate between the spent fuel pool and the cask pool. The HP technician agg;essively monitored radiation levels for the mechanics working on the gate and provided guidance to the mechanics on good work practices. In addition, the technician informed observers about the radiation levels in their areas and hot spot areas to avoid. The technician provided excellent
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HP cove:sge for the mechanics and observers during the spent fuel pool gate repair R4.2 Tendon Gallerv Contaminated Area - Unit 3 Insnection Scone (71750)
The inspectors performed a tour of the Unit 3 tendon gallery and identified water ;
crossing a contaminated area boundary. The inspectors informed HP about the finding and discussed the control of contam'nated
. boundaries with the HP manager, Observations and Findinas On October 7,1997, the inspectors identified a pool of sttnding water that crossed a contaminated area boundary in the tendon gallery and informed HP. HP conducted surveys of the_ area and noted a'l surveys outside the posted area were less than 1000 dpm per 100 centimeters squared and two surveys inside the contaminated-area were 1000 dpm per 100 centimeters squared. A sample of the water showed Cr 137 activity of 1.457E 7 micro curies per cubic centimeter, with one isotope.
l On October 8,1997, HP decontaminated and released the are Upon further investigation, the licensee identified that the area had been previously surveyed on August 10,1997. The survey results identified water crossing the contaminated area boundaries. The licensee indicated that the area should have been surveyed and released at the first discovery of water in the area or the contaminated area boundary should have been expanded to encompass the water if the area could not be released at that time. However, the HP supervisor who approved _the survey did not believe there was a contamination control problem, based on past experience with the same condition. HP management reaffirmed j expectations for appropriate response to such conditions w th the HP supervisor, Conclusions Untilinformed by the inspectors, HP supervision did not aggressively address a condition, previously identified by the licensee, where water crossed a contaminated
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boundar V. Wlanagement Meetings X1 Exit Meeting Summary I
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The inspectors presented the inspection results to members of licensee management at the exit meeting on November 13,1997. The licensee acknowledged the
. findings presented.
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iThe inspectors asked the licensee whether any materials' examined during the --
inspection should be considered proprietary. -No proprietary information was
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i ATTACHMENT SUPPL F. MENTAL INFORM ATION PARTIAL LIST OF PERSONS CONTACTEQ Licensee D. Brieg, Manager, Station Technical
J. Clark, Manager, Chemistry J. Fee, Manager, Maintenance G. Gibson, Manager, Compliance D. Herbst, Manager, Site Quality Assurance 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 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 92712: In office Review of LER IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering ITEMS OPENED AND CLOSEQ Ooened 361/97023-01 IFl applicability of instrumentation to EDG TS Closed 361; 362/96015-02 IFl UFSAR discrepancy 361; 362/97012-05 VIO failure to submit an LER within 30 days 361/97017-02 VIO power ascension with f ailed fuel pin 361/97017-03 VIO VCT inlet diversion valve in incorrect mode
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I 361; 362/97019-02 IFl painting inside the control room envelops 361/97 007 01 LER missed surveillance test for the containment exhaust radiation monitors 362/97 001 00 LER reactor coolant system leakage instrument thermowell nozzles 362/97 002 00 LER reactor coolant system leakage instrument thermowell nozzles 361/97-004-00 LER reactor coolant system leakage pressurizer thermowd LIST OF ACRONYMS USEQ CCW component cooling water CREACUS control room emergency air clean up system CVCS chemical and volume control system dpm disintegrations wr minute EDG emergency dief.el generator HP he,alth physict l&C instrumentatk n and control LER licensee event report PAMI postaccident monitoring instrument OSPDS qualified safety parameter display system SPM supervisor of plant maintenance SWC saltwater cooling TS Technical Specification UFSAR Updated Final Safety Analysis Report VCT volume control tank
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