IR 05000361/1997019
| ML20212A107 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 10/10/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20212A059 | List: |
| References | |
| 50-361-97-19, 50-362-97-19, NUDOCS 9710230158 | |
| Download: ML20212A107 (27) | |
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ENCLOSURE 2 l U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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-Docket Nos.: 50 361 '
50 362 License Nos.: NPF 10 NPF-15 Report No.: 50 361/97 19 50 362/97 19 Licensee: Southern California Edison C i Facility: San Onofre Nuclear Generating Station, Units 2 and 3 ,
Location: 5000 S. Pacific Coast Hw San Clemente, California Dates: August 17 through September 27,1997 Inspectors: J. A. Sloan, Senior Resident inspector J. J. Russell, Resident inspector J. G. Kramer, Resident inspector W. P. Ang, Senior Reactor Inspector, Engineering Branch Approved By: D. F. Kirsch, Chief, Branch F, Division of Reactor Projects
- ATTACHMENT: Supplemental Information 9710230150 971010 PDR ADOCK 05000361-G PDR
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EXECUTIVE SUMMARY San Onofre Nuclear Generating Station, Units 2 and 3 NRC Inspection Report 50 361/97 19; 50 362/97 19 This routine announced inspection included aspects of licensee operations, maintenance, engirsering, and plant support. This report covers a 6 week period of resident inspection; in additic,n, it includes the results of an announced inspection by a regional reactor inspecto Operations
Plant personnel performing walkdowns were inattentive to several discrepan'
conditions later identified by the inspectors. Licensee response to the inspectors'
observations of deficiencies was good (Section O2.1).
The inspectors identified a f ailed core protection calculator (CPC) module that, on subsequent evaluati on, was operable. The operators removed the CPC from service in a controlled manner. In this instance, operators demonstrated weak control board awareness (Section 04.1).
An operator's identification of a blinking yellow light on a circuit card, which indicated a failure of an underfrequency permissive for a Unit 3 emergency diesel generator (EDG), demonstrated good attention to detail while performing rounds outside the control room (Section M1,4).
Maintenaneg
Electrical Maintenance personnel used multiple methods to verify correct retermination of leads to a failed EDG relay, demonstrating good skill of the craft (Section M1.4).
Fire fighters performing a surveillance exhibited detailed technical knowledge and good cornmunication practices (Section M1.5).
Electrical Test technicians failed to properly secure test equipment in accordance with seismic requirements, resulting in a noncited violation. The test equipment was mon!!oring for grounds on safety-related switchgear. The Electrical Test technicians had a poor understanding of the requirements for properly restraining the equipment (Section M4.1).
Enainee'ina a
Poor communications were observed between Nuclear Engineering Design and Operations. As a result, procedural requirements for component cooling water (CCW) surge tank level, with an emergency cooling unit (ECU) operating,
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3-were inconsistent with calculations and plant configuration. The procedural restriction error was in a conservative direction (Section M1.3).
A design engineer's identification that a calculation for CCW backup nitrogen supp;y volume was not conservative demonstrated good attention to detail. Engineering work performed as a result of the identification was rigorous and thorough (Section E1.1).
A violation was identified as a result of inadequate quality in the procurement process. Licensee procurement personnel failed to include sufficient requirements in a purchase order to ensure adequate quality of steam generator manway gasket This resulted in a gasket leaking after installation in Unit 2. In this instance, procurement personnel demonstrated poor control over the procurement process (Section E8.5).
Plant Sucoort
Communications between Maintenance and Radiological Protection (RP) were weak in that Maintenance did not inform RP when completing work in a contaminated area. RP was not aggressive in monitoring and removing a contaminated area exposed to the environment. Documentation of radiological survey results was weak in that a survey performed on June 6,1997, was not documented unti!
September 19,1997 (Section R1.1).
A violation was identified by the inspectors as a result of not disabling an unoccupied vehicle inside the protected area. Communications between Security and the Fire Department were weak, in that the security requirement to disable an unoccupied vehicle was not understood by Fire Department personnel (Section S1.1 *
A noncited violation was identified by the inspectors as a result of Security personnel using an incorrect revision to a procndure. Security personnel displayed a lapse in attention to detail by not ensuring that the procedure used for log key issuance was the correct revision (Section S3.1).
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Report Details Summary of Plant Status Units 2 and 3 operated at essentially 100 percent reactor power during this inspection perio I. Operations 02 Operational Status of Facilities and Equipment 0 ElgnLWflkdown Observations - Units 2 and 3 Inseection Scone (71707)
During this inspection period, the inspectors performed walkdowns of the accessible i
areas of Units 2 and 3.
l l Observations and Findinas
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On August 25,1997, the flash arrestor cap on Class 1E Dattery 3D3 was found cracked. in response to the inspectors' observation, licensee personnel inspected other Class 1E flash arrestor caps and found an additional 38 caps that were deficient. An action request (AR) was generated to replace the cracked caps. The batteries remained operable with cracked flash arrestor cap On August 27,1997, Unit 2 Steam Generator E088 Main bream isolation Valve 2HV8205 hydraulic oil reservoir level was high, above the posted specification, by about 3/4 inch. Valve 2HV8205 remained operable with the as found hydroulic oil level. The licensee generated an AR to lower the level and was evaluating widening the specification on acceptable oil leve On August 27 28,1997, oil accumulation was obse ved on the pump support platforms beneath the Unit 2 Containment Spray Pump 2P012 and the Unit 3 High Pressure Safety injection Pump 3P018. The licensee was aware of both oilleaks, as evioenced by an AR being in place. However, the amount of oil demonstrated that leaking oil was not routinely cleaned u On September 3,1997, in the Units 2 and 3 saltwater cooling pipe tunnel, the inspectors identified leakage from four separate welds in a 20 foot pipe in a system that was posted as being potentially contaminated. The system leaked onto saltwater cooling piping and onto the floor, in response to the inspectors'
observations, licensee Health Physics technicians surveyed the area and found no contamination. The pipe, which was part of a system that had been abandoned in place, was not safety relate _______ . _ _ , _ . _ . _ . _ -_ . _ _ _ _ _ _ _
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, Conclus.lons ,
j Licensee response to the inspectors' identified deficiencies was good. However, '
plant personnel exercised a less than adequate level of attention to detail as they performed walkdowns, as evidenced by the leakage from a (posted) potentially
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contaminated system, the main steam isolation valve high hydraulic oillevel, and i
j the cracked battery flash arrestor caps.
04 Operator Knowledge and Performance
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04.1 CPC Failure - Unit 3 l Insoection Scoce (71707) '
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The inspectors performed a routine control room walkdown and identified a failed i
CPC module. The inspectors monitored the operators removing the CPC channel j- from service, Observations and Findinas
! On August 26,1997, at 3:15 p.m., the inspectors observed that the CPC
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Channel C display module was locked up and informed the operators. The failure of !
the CPC module did not cause any annunciation. The control room staff had not
] previously recognized the lockup and had previously observed that the module was
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- 30 p.m. The control room supervisor requusted Maintenance and j Engineering support to evaluate the failure, and subsequently declared the channel
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inoperable. The operators performed the actions of Procedure SO23 3 2.13, " Core r Protection / Control Element Assembly Calculator Operation," Revision 9, for
! removing the CPC and control element assembly calculator from service in a l methodical and controlled manner. The licensee subsequently concluded that the
} display module failure did not render the CPC inoperable.
! Conclusions
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j The operators board awareness was weak in that the operators did not recognize a
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failure of the CPC module.
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11. Maintenance
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M1 Conduct of Maintenance M1.1 General Comments i insoection Scone (62707)
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The inspectors observed all or portions of the following work activities:
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- Thermographic investigations on Class 1E pressurizer Heater
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Breakers 2 BHP 0801 and 2 BHP 0802 (Unit 2)
Calibrate Train B Emergency Chiller E335 gas bypass motor actuator thetmostatic switch (Units 2 and 3)
- Gas sampling system blower repelr (Units 2 and 3)
, Observations and Findinga l The inspectors found the work performed under these activities to be thorough. All
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work observed was performed with the work package present and in active use.
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Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality
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control personnel.were present whenever required by procedure. When applicable, appropriate radiation controls were in place.
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in addition, see the specific discussion of maintenance observed under Section M1.4, belo <
M1.2 General Comments on Surveillance Activities , Insoection Scope (61726)
I The inspectors observed all or portions of the following surveillance activities:
- Water Inventory Balance (Unit 2)
- Turbine-driven Auxiliary Feedwater Pump P140 Quarterly Surveillance ,
(Unit 3) ' Observations and Findinas
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The' inspectors found all surveillances performed under these activities to be thorough. ail surveillances observed were performed with the work package
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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 ,
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in addition, see the specific discussions of surveillances observed under Sections M1.3 and M1.5, belo M1.3 Weak Communications Between Nuclear Desian Ennineerino and Ooerations Insoection Scone (71707,61726,37551)
The inspectors reviewed the implementation of Unit 2/3 Surveillsnce Requirement (SR) 3.6.6.1.3, verifying a CCW system flow of at least 2000 gallons per minute to each containment ECU. The SR is to be performed once every 31 days. The inspectors reviewed Procedure SO23 XV-3, " Technical Specification Surveillance Program implementation," Revision 7; Procedure S023 3 3.43.38,
"ESF Subgroup Relays K 306A and K 306B Semiannual Test," Revision 2; Procedure SO23 3 3.13, " Containment Cooling / Spray Monthly Tests," Revision 0; and Procedure SO2315 64.A, "CCW Surge Tank Train A Level Hi/Lo," Revision 2 Attachment 2, Section 64A26. The inspectors also reviewed AR 960801324 and Nonconformance Report (NCR) 960801324. In addition, the inspectors interviewed Operations and Engineering personnel, Observations and Findinas Based on a review of the documents listed above, the inspectors found that Procedure SO23 3 3.13 adequately implemented the SR with the CCW system aligned for accident loading.
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Containment ECUS are cooled by CCW and ere used to provide containment cooling and pressure control during design basis events. Procedure SO23 3-3.13 listed, as an initial condition for operating ECUS, that CCW surge tank level be greater than or equal to 45 percent. In addition, Procedure SO23 217 stated that CCW surge tank level had to be greater than or equal to 45 percent level to maintain the operability of the ECUS when ECU fans were in service.
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The basis for the 45 percent level requirement for on operating ECU was listed in the procedure as AR 960801324. This AR had been generated in response to NRC Information Notice 96-45, which alerted licensees to the potential for water hammer in CCW piping at the ECUS. Licensee design engineers determined that if an ECU was operating, and a containment cooling actuation signal was received, followed by a loss of offsite power signal, then loads would be stripped and resequenced. The ECU fans would then restart at 5 seconds, and bw hot air past the stagnant CCW water. When the CCW pump restarted at 15 se.conds, cool CCW water might cause a water hammer effec The licensee had initiated NCR 960801324 as the result of the potential safety implications. The NCR concluded that no level sestriction was required to prevent water hammer, but that restrictions on CCW surge tank pressure and CCW temperature were sufficient. However, approdmately eight procedures that had incorporated the restrictions on level were not updated. During the Cycle 9 refueling outages, a design change was made to cause CCW pump start prior to fan
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start for automatic loss of coolant accident sequencing. However, again, no procedure changes were made to lif t the level restrictio The inspectors found that, because no mechanism existed to csuse the restrictions to be lifted as the NCR was finalized, and af ter the design change package was implemented, th6 licensee procedures group lef t unnecessary operational restrictions in the procedure. As a result of the inspectors' findings, the licensee planned to remove the restriction The licensee did have requirements to evaluate procedures which were impacted as a result of design changes (Procedure SO123 XIV 4.2, " Station Review, Approval, and Closeout of Design Changes for SONGS Units 1,2, and 3 (DCPs, MMPs, FCEs, PFCs and LCPs," Revision 5). However, since the design change to the sequence of equipment starts was performed to provide additional margin for CCW operability, end had no effect (in and of itself) on the erroneous level restriction discussed above, no violation of licensee procedure with respect to the design change occurred. The design change was, however, a rnissed opportunity to identify the erroneous, excessively conservative, level restrictio The inspectors also reviewed historical data for CCW surge tank level and identified that Unit 3 Train A CCW surge tank level had dropped below 45 percent, to about 44 percent, for about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> on September 2,1997. Unit 3 Train A CCW surge tank level also dropped below 45 percent for less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, to about 44.5 percent, on September 7,1997. Since no procedural requirements were in effect for CCW surge tank level without ECUS in service, cxcept for a 25 percent level for CCW system operability, the inspectors found that although the operators had allowed the level tc go slightly low out of the green band on control room lumigraphs, no procedures had been violate Procedure SO23 XV 3 contained a list of Technical Specification SRs and the corresponding procedure that implemented the SR. SR 3.6.6.1.3 was indicated as being implemented by Procedure SO23 3 3.43.38. The inspectors identified that this was an incorrect reference, and that Procedure 8023 3 3.13 actually lo1plemented SR 3.6.6.1.3 Procedure SO23 XV-3 was maintained by the Nuclear Regulatory Affairs group. The licensee was reviewing this procedure, as part of an ongoing review not prompted by this incorrect reference, to identify other discrepancies, and planned to conect this discrepancy (which the licensee had already identified) when the review was complete. The inspectors found this was an acceptable response to their observations, c. Conclusion Operators allowed surge tank level to go slightly low out of the green band with no operational safety consequences. Also, poor communications between Nuclear Engineering Design and Operations resulted in procedural requirements not reflecting current calculations and plant configurauon. These procedural requirements were overly restrictiv .
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- M1.4 StDlacemeyt of EDG 3G002 Underfrecuency Relav Unit 3 (62707)
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On September 5,1997, the inspectors observed electrical maintenance personnel rescing a microprocessor relay for Unit 3 EDG 3G002. An equipment operator h&d noticed that a yellow bpm was blinking on the circuit card. Normally, the yo!!cw ilght was not illuminated. The light indicated that the relay was set, and that, consequently, an underfrequ3ncy permissive was enabled. The
! underfrequer.g permMvo in6cated that the EDG was at running frequency:
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however, whp. the ope.rstor noticed the light the ED3 was not operating. The
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licensee conservativedy notisrod the EDG inoperable, even thovC) the permissive being set would not disable EDO start.
i l Electrical maintenance personnel used Procedure SO123 ll 15.3 (a lifted lead form)
j . to verify proper retermination of the leads on the new microprocessor. A digital
- photograph of the old microprocessor with wire designation legible was used to 1 provide a second check of the reterminatio The inspectors found that the operator's observation of the yellow light on the j circuit card demonstrated caod attention to detail while performing rounds. The i electrical maintenance personnel's use of the digital photograph demonstrated good skill of the craf t, beyond what was required in the written maintenance order.
! M1.5 Selsmic Tractor, Pumo, and Tanker Insoection Surveillance (61726. 71750)
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' On August 25,1997, the inspectors observed Fire Department personnel perform portions of Procedure SO23 XV 4.67, " Seismic Tractor, Pump, and Tanker Inspection," Revisien 2 Attachment 3. The fire fighters performing the surveillance
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exhibited detailed iachnical knowledge of the equipment, used closed loop communications, and effectively performed the surveillance. The performance of the fire fighters, with respect to compliance with security requirements, is discussed in Section S M4 Maintenance Staff Knowledge and Performance M4.1 Electrical Test Eauioment Not Seismically Secured Unit 3 Insoection Scoce (62707)
On August 25,1997, the inspectors walked down the Unit 3 Train B Class 1 switchgear roo Qbservations and Findines The inspectors observed elecitical recording devices on the top of a wheeled car The cart was installed on August 20,1997, to activate and then record Class 1E 480 Volt Electrical Bus 3B00 parameters, including secondary transformer potential, due to earlier intermittent ground indications. The cart was installed in accordance with Maintenance Order 97080884, which included a safety evaluation for installing
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7 I the monitoring equipment on an operable safety-related electrical bus. The inspectors observed that the cart and recording instrumentation were not installed in compliance with Procedure SO12311.20 " Seismic Controls," Temporary Change
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Notice (TCN) 41, because the cart's wheels were blocked, and the recorder on the 1
top of the cart was not secured to the cart. Step 6.3.13.1 of the proceoure stated !
"The small equipment (weight less than 50 pounds) is to be restrained to the cart or table . . ." and Step 6.3.13.2 stated "The cart or table is to be anchored to a permanent civil structure . . . ." Contrary to these requirements, the cart was not anchored and the equipment on top of the cart was not restrained. However, the top of the cart had a ncn skid surface, minimizing the potential for equipment to !
slide off. The cart was adjacent to the rear of Class 1E Bus 3B06 and within a fall radius (about 2 feet away, with an approximate cart height of 4 feet) of numerous
Class 1E 480 volt breaker !
- In response to the inspectors' observations, Maintenance personnel removed the
- cart. The inspectors questioned two electrical test technicians and the supervisor '
l of electrical maintenance and determined that the electrical test technicians were i familiar with Procedure SO12311.20, but did not understand the requirements for i seismically restraining a test cart and equipment. Event Report 97081306 was
! generated (a licensee internal method of documenting human errors), and l Maintenance supervision reviewed the occurrence with the electrical test
- technicians, as well as other work groups. Maintenance supervision walked down ,
other areas to identify any other problems, and also provided a focus to the licensee i leadership observation program in the area of seismic restraints. Licenseo management indicated that Procedure SO12311.20 would be changed to clarify the requirements. The inspectors considered these corrective actions adequate.
l_ The failure of the electrical test technicians to follow Procedure SO12311.20 was a
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violation of Technical Specification (TS) 5.5.1,1.a. This failure constitutes a violation of minor significance and is being treated as a noncited violation,
- consistent with Section IV of the NRC Enforcement Policy (NCV 362/97019 01).
i Conclusions Licensee electrical test technicians demonstrated a poor understanding of the f requirements for properly securing test equipment, resulting in a noncited violation.
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M8 Miscellaneous Maintenance issues (62707)
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- M8.1 Paintina ins!de the Control Room Envelooo - Units 2 and 3 i
j Insoection Scooe (62707)
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During this inspection period licensee maintenance personnel were performing a co.. trol room upgrade project. The work activities included painting inside the i control room emergency air cleanup system (CREACUS) boundary. The inspectors
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reviewed this painting in terms of the operability of the CREACUS units.
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b. Qhservations and Findinas During painting periods and for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> immediately thereafter, licensee personnel removed DC control power frorn the main fans associated with one train of CREACUS. A 7 day shutdown limiting condition for operation was entered for one train of CREACUS out of service. Licensee management explained that this was to protect the disabled train from an automatic initiation in order to maximize charcoal life and system availability. One train starting could cause the charcoal to be exposed to volatile organic compounds from the paint fumes, and shorten the charcoallife. The inspectors reviewed controls on the amount of paint as specified in Procedure SO23 3 2.7, " Control Room isolation and Emergency Ventilation System," Revision 8, and considered that the train left available was operable, and that voluntarily entering the limiting condition for operation was acceptabl The inspectors also reviewed testing requirements for the CREACUS units as required by TS and described in Regulatory Guide 1.52, Revision 2. The CREACUS trains did not have dampers internal to the CREACUS boundary such that the CREACUS units were isolated from the spaces in which painting was occu. rin Regulatory Guide 1.52 stated that charcoal samples were required to be drawn if the CREACUS units were in " communication" with spaces being painted. The licensee was not planning to take, and had not historically taken, samples after painting unless an inadvertent initiation were to occur. On September 19,1997,a conference call between members of the licensee staff and the NRC Office of Nuclear Reactor Regulation Systems branch took place. The NRC's position was that communication meant open ducting, and that either the ducting should be sealed or tests conducted to demonstrate that volatile organic compounds were not coming into contact with the charcoal. Licensee management presented qualitative data concerning painting in 1988,1990,1991, and 1993, and results of nc mal 18 month charcoal samples indicating efficiency above 99 percent, with no charcoal replacements. The licensee also described controls in place to limit the amount of paint, hoods, and portable cleanup units used. The licensee planned on doing a quantitative analysis of the painting mentioned, in comparison with the painting being done this report period, to demonstrate that the CREACUS units were not being adversely affected by the current painting. The inspector will review this analysis as a follovsup item (Inspection Followup Item 361;362/97019-02),
c. Conclusions An ini,pection followup item was created to review a licensee assessment of the quantity of previous painting in the CREACUS boundary. This assessment was planned to demonstrate that, during the painting done during this inspection period, there was no " communication" of volatile organic compounds from the spaces being painted to the CREACUS unit _ _ _ _ _
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111. Eonineerina E1 Conduct of Engineering E CCW Backuo Nitroaen Sucolv - Units 2 end 3 Insoection Scoce f71707,375511 On August 14,1997, licensee design engineers determined that Calculation M2717, used to support nitrogen cover pressure requirements for the l CCW surge tanks, was nonconservative. The inspectors reviewed licensee actions
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taken as a result of this determinatio ' Observations and Findinas The CCW surge tanks are provided with a nitrogen cover gas. The normal source of nitrogen is not safety related. Backup nitrogen bottles are installed to provide a safety-related supply of nitrogen for 7 days. The design engineers determined that the calculation for the quantity of the 7 day supply did not account for nitrogen losses from increasing surge tank level. As operators increased level, the nitrogen gas volume in the surgo tank would be compressed and pressure would rise. A pressure control and/or relief valve would open, lowering pressure and causing a loss of nitrogen. Minimum tank pressure, while backup nitrogen was in service, was regulated at 38 1 psig. Maximum pressure was set by the pressure control valve, which also acted as a system relief prior to the opening of a separate relief valve. The pressure control valve was set at 41 1 psig, Jonsequently, the operating band from tank pressure to the pressure control valve setpoint could be as little as 1 psi with backup nitrogen in service. Levelincreases above 1 percent could cause the pressure control valve to lift. Minimum pressure was based on operability of the CCW system. A regulator common to both the normal and backup nitrogen supplies provided about 34 psig nitrogen pressure to the CCW surge tanks with normal nitrogen in service. Because the backup nitrogen bottles were at higher pressure than the normal supply, the regulator provided the 38 psig discussed above with backup nitrogen in service. Maximum pressure was based on system rating On August-14,1997, Operations personnel initiated an abnormal alignment for both Units 2 and 3 (Log Number 2/3 97136) in order to control level increases in the CCW surge tanks in the event of a design basis accident requiring the 7 day supply to maintain CCW surge tank level. Safety-related makeup to the CCW surge tanks in provided by emergency makeup pumps, and the abnormal alignment required opening a makeup pump vent line to provide recirculation, and manually throttling makeup to control CCW surge tank pressure increase. On August 15,1997, Operations personnel revised the abnormal alignment (Log Number 2/3 97140) to open both the vent line and a test line, to increase recirculation flow. This abnormal alignment remained in effect at the end of this inspection period. The licensee planned on increasing the setpoint of the syster.1 relief valve, in order to provide more margin for pressure changes, after evaluating ASME Code restraint __ _ _ . . . . .
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l The inspectors reviewed the informal calculations that the engineers originally developed to determine minimum recirculation requiremenu, and found the calculations consuvative in terms of the mechanical and thermodynamic thought processes used. For instance, the original calculation of increase in water temperature, assuming flow only through the vent line, assumed all work done by 1 the pump motor was transferred into an increase in temperature of the fluid, and i neglected increases in the pressure and elevation of the fluid, as well as ambient l losses. After the original abnormal alignment was in effect, the engineers contacted
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the pump vendor, who recommended an increased flow, using a higher fluid ;
temperature and less suction head than the engineers had assurned, or that would be present in a design basis accident. The engineers made a conservative decision to increase the flow. The inspectors found that the engineering calculations and processes throughout were conservative. The inspectors also found the licensee's evaluation of the original concern and review of the calculation were thoroug The licensee's intermediate term actions (increasing the upper pressure restrictions on the CCW aurge tank) and long term actions were incomplete as of the end of this inspection period, c. Conclusions Nuclear Engineering Desiga engineers demonstrated good attention to detail while reviewing calculations, and the engineering work performed as a result of the identification was conservative and thoroug '
E2 Engineering Support of Facilities and Equipment E Batterv Cell Debris - Units 2 and 3 (37551)
On September 9,1997, the inspectors observed a piece of tubing in the lower corner of Cell 36 of Battery 3D4 and informed the licensee. The licensee performed a walkdown and identified two additional cells with tubing in them, one additional cellin Battery 3D4 and one in Battery 2D3. The licensee performed on operability assessment of the batteries and concluded that the batteries were operable based on a previous NCR for a similar issue, and on conversations with the battery manufacturer. The licensee identified that the tubing was from an extension tube norrnally used with a bulb type hydrometer; this type of hydrometer had not been used in the safety batteries for over 3 years. The inspectors concluded that the licensee thoroughly addressed the issue of the battery cell debri E8 Miscellaneous Engineering issues (92700,92903)
E (Closed) Inspection Followun item 361;362/96011-02: charging pump seal water power supply (Updated Final Safety Analysis Report (UFSAR) error).
This item involved inspector identification of an instance in which the UFSAR was not accurate. The UFSAR indicated that seal water power supplies for charging pumps were from a Class 1E source: however, the as built configuration provided
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power from a non Class 1E source. Based on NRC review of the bcensee's operability assessment showing that the charging system was operable in the as-built configuration, the technical issue was determined to be of no significanc The inspectors reviewed UFSAR Change Request SAR 23 543, and determined it was sufficient to correct the inaccuracy in the UFSAR with regards to the power supply. The inspectors also found that this change to the UFSAR did not represent an unreviewed safety questio E8.2 (Ocen) Unresolved item 361:362/97012-07: charging system check valve failure This item involved review of the safety significance, procurement, and postmodification testing regarding the licensee's discovery that some charging system check valves were not functioning properly. The inspectors reviewed a summary of the purchase order used by Bechtel personnel acting for licensee procurement personnel to obtain the valves around 1985, reviewed portions of Chapter 15 of the UFSAR, and interviewed procurement personnel. The inspectors also reviewed Licensee Event Report (LER) 361;362/97 010, Revisions O and 1, l generated as a result of this occurrenc Revision 1 of the LER stated that the cause of the failure of check valves in Units 2 and 3 charging injection and auxiliary spray lines was a design defect in the valve The valves were Kerotest 2 inch Y type Series 1513 check valves. Chapter 15 of the UFSAR did assume a charging flow of 15.8 gpm in maintaining emergency core cooling system acceptance criteria,in accordance with 10 CFR 50.46, for reactor coolant system breaks less than 0.1 square feet. The 1985 purchase specifications
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used to obtain redesigned Series 1513 valves (the valves of concern for failure)
resulted in installation of a total of 17 valves in safety related applications during and after 1985. The specifications used to purchase these valves were apprcpriate for the applications use The failure mechanism described by licensee engineers was that over a period of time the valve disc induced a notch in the interior of the cylindrical valve body at a position less than full open. This notch then caused the disc to become mechanically bound within the valve body in a position less than full open. This position prohibited full flow through the valve. Consequently, the valve would have allowed full flow at the time of installation, but later would have prohibited full flow as the notch became pronounced enough to cause the rnechanical bindin Postmodification testing would not have indicated the defect, since the defect would not have been present when the new, redesigned valves were installed in 155 The finallicensee root cause determination had not been completed as of the end of this inspection period. This item remains open pending review of the formal licensee root cause report, in order to assess whether or not a design problem exists for these valve l
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) E8.3 (Closed) LER 361; 362/97 010 Revisions O and i: charging subsystem check valve i failure. This issue is being reviewed as part of Unresolved i Item 361; 362/97012 07.
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! EB.4 (Closed) LER 361/97 009-00: Class 1E 125 VDC battery surveillance testin '
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- In a June 4,1996, letter to the NRC, the licensee committed to complete a
TS-required performance test (verify battery capacity is equal to or greater than ,
1 80 percent of the manufacturer's rating) in addition to the TS required service test '
(verify battery capacity is adequate to supply and maintain the required loads for the '
- design duty cycle) for Batteries 2D1 and 302 during the Cycle 9 outages.
f ( The licer.see completed the performance test before the TS required service test.
! The licensee and the vendor recognized a longer equalizing charge than normally j performed (11 days rather than 2 days) would be necessary to restore the battery
- to a condition similar to its preperformance test condition before performing the j service test. The TS bases for both tests require "as found" conditions. The
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!- performance test was as required by TS. However, the licensee commitment was
] to perform the test even though it was not required to be performed by TS
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! periodicity. In the LER. the licensee questioned if recharging the battenus would *
affect the "as found" conditicns. Because battery capacity cannot be increased lay longer charging times, the licensee concluded that this would be acceptable and would not be preconditioning.
- Due to the recharging concern, the licensee also questioned if including spare cells in the TS SRs (and prorating the results downward) was a pretest enhancement.
- The licensee concluded that aligning the two spare cells to the battery being tested ,
l did not constitute a pretest enhancement because doing so cannot improve the
- ability of the battery to pass the surveillance.
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The licensee planned to revise the bases for TS 3.8.4.7/8 to clearly indicate that
) battery recharging between tests may be required, and that spare cells may be j included during surveillance testing.
! The inspectors concluded that the licensee's battery testing inethodology was j acceptable.
i l E8,5 (Closed) Unresolved item 361/97005 04: incorrect steam generator primary i manway cover gasket installed.
, Insoection Scone (90712. 92700)
- The inspectors reviewed licensee actions associated with Corrective AR 007 97 to determine the adequacy of licensee actions for the conditions associated with the Steam Generator 2E089 cold leg manway cover leak. The inspectors reviewed ARs, procedures, and documents and discussed the evaluations and corrective
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actions with various licensee pctsonne r
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Backoround
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j On March 22,1997, after the plant was heated up to Mode 3, the licensee
identified a small amount of leakage from the Steam Generator 2E089 cold leg a
manway cover. The licensee reviewed the maintenance records and verified that l the gasket was new and that the correct stud tension had been achieved during
, installation. The design provided for a substantial margin and leakage was not e':pected to occur. Because the leakage indicated an unusual condition, the t j licensee returned the plant to Mode 5 condition to evaluate the cause of the i leakage.
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The licensee determired that the gasket installed was not correct for the application in that the installed gasket was designed for a 900 psi application and not the
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2500 psi required for the reactor coolant system pressure boundary. The steam l
generator cold leg manway cover gaskets had been classified as nonsafety-related in a change made in 1989 by Combustion Engineering (CE) and accepted by the j
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licensee. The gasket had been ordered from a third-party vendor, Pacific Mechanical Supply, with the intent that the vendor would obtain the gasket from CE. The purchase order did not provide design specifications for the gasket, but i
listed the CE part number and provided a general description (nominal dimensions, i
materials, and gasket type). The design specification , were proprietary to CE. The
licensee had met with Pacific Mechanical Supply and other vendors in mid 1996 to
, explain that if a part was ordered by part numberi substituted parts would not be J
accepted. However, this condition was only verbal. Prior to 1996, this condition .
had been included as part of the written purchase orde .
- The inspectors reviewed the licensee identified discrepancies associated with the
, leaking steam generator manway and gasket. The inspectors noted that the
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licensee issued Corrective AR 007 97 to determine the root cause of the problem and establish the necessary corrective actions. The inspectors identified the installation of the incorrect gasket as an unresolved item pending a review of licensee actions associated with Corrective AR 007 97.
j Followuo insoection j The inspectors reviewed the following ARs and di= cussed them with the licensee:
970201509 2/26/97 - Steam generator primar e manway gaskets in the warehouse are thicker than the gecified design.
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- - 970400152 4/3/97- Replacement steam generator and pressurizer manway gaskets were purchased from nonoriginal equipment manufacturer (OEM) source. The gaskets did not meet original equipment requirements (unknown pressure rating, dimensional discrepancies); upon installation in Unit 2 the gaskets leake . _ . .-_ .
970401320 4/22/97 Blanket Purchase Orders 602T2901 and 6K684901 were identified as not incorporating the current technical / quality requirements of PEPS 2ES0090 and 6MN0015, respectively. Review :urrent quality affecting blanket purchase order *
970501180 5/16/97 Corrective actions from failure analysis Report 97 014 on the ' steam generator primary manway Manway stud preload uncertainties associated with tensioning versus torquin The inspectors determined that CE Drawing E 234 708, " Miscellaneous Details San Onofre lil Steam Generators," Revision 2, required the primary manway cover gasket to be a Part Nuinber 119 07, "manway gasket, 18" OD x 16-1/8" ID x 0.175" thick, SST and asbestos, flexitallic special." The licensee informed the inspectors that historically, since 1989, the gaskets were procured from, and supplied by, the OEM, CE, as a nonsafety-related gasket. The licensee further informed the inspectors that in mid 1996, some nonsafety-related commodity iteme were placed on corporate purchase orders. The licensee stated, however, that the steam generator manway gaskets were elways intended to be procured from the OEM because sufficient TSs for the gaskets had not been provided. Nonetheless, the gaskets were placed on the corporate blanket data interface and, on August 1,1996, a purchase requisition worksheet for the gasket was initiated with the drawing description and CE part number. On August 21,1996, the licensee's warehouse received ten gaskets from a vendor, Pacific Mechanical Supply, described as CE Part Number 119-07161/8" ID x 18"OD r 0.175" THK size,304 SS with asbestos material, spiral wound style.
AR 970201509 noted on February .8,1997, that the available steam generator primary manway gaskets in the warehouse were thicker than the specified design.
The gasket thicknesses were approximately 0.183 inch rather than the design value of 0.175 inch Licenseo Site Technical Services engineers evaluated the reported condition and noted that the measurement was taken using a scale reading micrometer. Site Technical Services engineers dispositioned the AR with a statement that subsequent measurement by an electronic digital micrometer determined the gasket thickness to be 0.177-inch, which was 3 mils below the upper thickness tolerance of 0.180-inch. The inspectors determined that licensee Site Technical Services engineers performed extraordinary evaluations of the gasket thickness in order to accept the gaskets. However, the licensee missed the opportunity, at that time, to question and confirm that the correct gaskets had been procured and/or received. Consequently, the incorrect gaskets were eventually installed.
AR 970400152 traorted on April 3,1997, that replacement steam generator and pressurizer manway gaskets were purchased from a non-OEM manufacturer source, did not meet original equipment requirements (unknown pressure rat ings and
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dimensional discrepancies) snd leaked subsequent to installation in Unit Corrective AR 007 97 was initiated as part of AR 970400152.
l The root cause of the condition stated in Corrective AR 007 97 was "All purchases of steam generator and pressurizer manway gaskets prior to August 22,1996, were made from CE, the OEM or their authorized equipment supplier (OES). Each gasket was identifiea by the CE part number specified on steam generator and pressurizer drawings, which is adequate and appropriate definition of technical requirements to assure compliance with ptant design, provided the part is purchased from CE. In the process of implementing strategic sourcing initiatives, these gaskets were placed on a blanket purchase order with a distributor who disregarded the CE part number specified and provided what he believed to be an appropriate gasket without further communication with either SCE or the OEM/OES."
The root cause evaluation further stated that " Changes in business practices both at SONGS and Lorporate Procurement and Material Management set the stage for misapplication of the controls and resultant placement of the gasket on a Corporate Strategic Sourcing Blanket Purchase Order that did not impose the appropriate restrictions against substitutions on the supplier." Purchase Order X3115902 was issued on August 8,1996, to Pacific Mechanical Supply for 10 steam generator manway gaskets with the CE part number and the CE drawing gasket description of size and type, but without a prohibition of substitution of parts. Furthermore, the purchase order did not contain sufficient information to alloN substitution of any other gasket for the CE par CFR Part 50, Appendix B, Criterion IV requires that measures be established to ensure that applicable regulatory requirements, design bases, and other requirements necessary to assure adequate quality are suitably included or referenced in the documents for procurement of material, equipment, and service Purchase Order X3115902 failed to provide sufficient requirements to assure adequate quality of the steam generator manway gaskets that were being procure The failure was considered to be a violation (Violation 361/97019-03).
The actiors taken/ planned to resolve the problem stated in Corrective AR 007-97 were as follows:
The procurement and installation of all nonsafety-related gaskets identified by an OEM/OES part number, and installed in safety-related components that could be exposed to reactor coolant system pressure were reviewed to ensure each gasket was obtained from the OEM/OES. Aside from the pressurizer and steam generator manway gaskets, the backup bonnet gasket on Valve 2PV0100B, the pressurizer spray control valve, was found to have been purchased from someone other than the OEM/OES. The licensee determined that the gasket had been installed for at least two fuel cycles and has performed satisfactorily with no i 'idence of leakage. The licensee concluded that it was acceptable for the gasket to remain installed, i
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- All automated procurement, and any new blanket purchase order releases for any nonsafety related parts of safety-related compnnents (310/313 material codes), were halted effective March 27,1997. Any requisition for such parts was required to be reviewed by procurement engineering prior to being placed on a purchase order to ensure that the purchase order contained all necessary provisions for the part. Where OEM/OES part numbered items could not be obtained, engineering evaluations of proposed substitutes was require *
The description field on all nonsafety-related components (310/313 material codes) were revised on the " Corporate Materials Management System" to include a statement that read 'DO NOT SUBSTITUTE" and "OEM/OES REQUIRED."
The classification of steam generator and pressurizer manway cover gaskets was changed from r ansafety-related to " Augmented Quality Class" material, which would add technical and quality assurance requirements on all future purchases. This provision would include receiving inspection and traceability requirement .
A comprehensive review of all current purchase orders for all nonsafety-related parts of safety-related components other than gaskets was performed to identify any parts, other than gaskets, that may have been similarly purchased from a supplier other than the OEM/OE The inspectors determined that the licensee had initiated comprehmsive reviews and corrective actions for the noted procurement problem, The inspectors noted that Corrective AR 007 97 and the Nuclear Oversight Division followup of the corrective actions provided reasonable assurance that the identified procurement problem would be corrected upon completion of the specified corrective action The incorrect gasket that the licensee installed in the cold leg manway of Steam Generator 2E089, discussed above, was removed and replaced with a gasket supplied by the steam generator OEM, Asea Brown Boveri-CE. The licensee installed the Steam Generator 2E089 cold leg manway cover and gasket using Maintenance Order 97021201001 and Maintenance Procedure SO23-I-6.113,
" Removal and installation of Steam Generator (Primary) and Pressurizer Manway Covers," Revision 6. The maintenance procedure provided two methods for preloading the manway cover studs. Section 6.9 of the procedure provided instructions for preloading the studs by torquing the nuts. Section 6.10 of the procedure provided instructions for preloading the studs by means of a hydraulic tensioner device. The maintenance order required the cold leg manway cover to be installed in accordance with Procedure SO23-1-6.113, Section 6.10, the hydraulic tensioning metho The inspectors determined that CE Book Number 71270, " Instruction Manual, Steam Generators, San Onofre Number 2, Southern California Edison,"
(SO23-915 69-0), dated February 1977 was the applicable Steam Generator 2E089
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vendor technical manual. The inspectors noted that the vendor technical manel instructions for installation of the cold leg manway cover and preloading the studs, Section 5 3 6, required torquing the nuts. Licensee engineers informed the inspectors that engineering calculations were performed to determine the amount of tensioning on the studs that would be required to attain the preload equivalent to the preload that would result from toiquing the nuts in accordance with the vendor technical manual requirement Licensee engineers informed the inspectors that the engineering evaluations and calculations were performed to ascertain the adequacy of the preload applied on the Unit 2 primary manway cover fasteners. Based on the calculations and description of the engineering actions, the inspectors determined that the licensee engineers performed reasonable evaluations of the adequacy of the preload arplied to the Unit 2 primary manway cover fasteners. However, the inspectors also noted that a more complete review would need to be performed to determine the assumptions contained in the CE calculations for the steam germated primary manway cover fastener preload. The inspectors noted that assumptions of several variables such as fastener thread dimensions, thread friction factor, nut to face friction factor, thread lubricant, fastener temperature, stack up of tolerances, etc., would need to be considered. In addition, variables associated with the hydraulic tensioner used by the licensee would also need to be considered. The licensee informed the insr.sctors that laboratory testing was planned, as part of corrective actions contained in ARs 970400152 and 970501180, to confirm the correlation between-the vendor manual required torque value and the preload applied using the hydraulic tensioner. The results of the laboratory testing for the confirmation of the correlation between the vendor technical manual required torque value and the hydraulic tensioner applied preload is considered to be an inspection Followup item 361/97019-0 Conclusions A violation was identified as a result of inadequ., quality in the procurement process and licensee Procurement personnel fail...g to include sufficient requirements in a purchase order to ensure adequate quality of steam generator manway gaskets. This resulted in a gasket leaking after installation in Unit 2. In this instance, procurement personnel demonstrated poor control over the procurement process, IV. Plant support R1 RP and Chemistry Controls R1.1 Contaminated Area (CA) Boundarv - Unit & Insnection Scone (71750)
The inspectors toured plant areas exposed to the environment to observe the radiological control practices and discussed the practices with the RP manager, b_-.--_-__--_.__________-------
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18 Observations and Findinos On August 21,1997, the inspectors observed a posted CA on the 96 foot elevation on the roof near the fuel building normal exhaust fan. The inspectors observed a blown-over bag of potentially contaminated waste that remained in the posted area, in addition, the inspectors observed evidence that rain water had washed through the area and into a roof drain and observed debris (sea gull feathers) blowing into and out of the CA. The inspectors informed RP regarding the condition of the C RP discussed the necessity of maintaining the boundary with Maintenance, and subsequently removed the boundary. RP identified no contamination present during the CA remova The licensee determined that Maintenance performed work inside the CA on June 6,1997, and then released the equipment back to Operations the same da However, RP was not informed that the work in the duct was complete and the maintenance order was not close Since the area was exposed to the environment, the inspectors asked RP personnel to provide radiological survey records documenting the history of the area. RP identified two survey records. The prejob survey performed on June 6,1997, indicated low levels of contamination present inside the duct where Maintenance personnel would be working. A routine survey performed on July 16,1997, indicated that the area was clea CFR 20.1501(a) requires each licensee to make, or cause to be made, surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20. These surveys are to be reasonable under the circumstances to evaluate the extent of radiation levels, the concentratior s or quantities of radioactive materials, and the potential radiological hazards that could be presen The inspector informed the RP manager that the two documented surveys did not satisfy the requirements of 10 CFR 20.1501(a).
On September 19,1997, the licensee contacted a contract RP technician whose name appeared on the June 6 survey. The technician indicated that his supervisor directed him to check the posting of this area. After checking the posting, the technician indicated that he wanted to ensure there was no removable contamination inside the CA, since the roof area was exposed to the weather. The technician performed masslinn swipes inside and outside the posted CA. All swipes were negative for activity. The technician indicated that he did not document the survey at that time because he did not realize that no surveys had been performed prior to his survey. The licensee subsequently documented the results of the contract RP technicians's survey. The inspectors concluded that the actions by the contract RP technician satisfied the requirements of 10 CFR 20.1501(a).
The licensee initiated an AR to evaluate the necessary corrective actions. RP supervision briefed the RP technician regarding the event and emphasized communications between RP and Maintenance, and also the expectation that surveys be documented. The leadership observation program willinclude the
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85 foot roof area (which includes the 96 foot elevation) as part of RP supervisor walkdowns. The licensee planned to formally add outside CAs as part of routine daily surveys, in addition, the licensee planned to develop a formal process of
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communications between Maintenance and RP concerning the completion of work
- in CAs.
$ Conclusions
) Communications between RP and Maintenance was weak in that Maintenance did
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not inform RP when completing work in a CA. RP was not aggressive in monitoring and removing a CA exposed to the environment. RP documentation of survey
results was weak in that a survey performed on June 6,1997, was not
, documented until September 19,1997.
! R8 Miscellaneous RP and Chemical issues (92904)
R8,1 (Closed) Insoection Followuo item 361:362/97012 10: acceptability of locb
{ room not being defined as a radiologically controlled area.
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This issue was opened to evaluate the acceptability of having a locker room (nonradiologically controlled area) that was only accessible by passing through a radiologically controlled area. Based on review of regulations, the inspectors j
concluded that the licensee's practice of having the locker room surrounded by a j radiologically controlled area was acceptabl S1 Conduct of Security and Safeguards Activities S1.1 Security of the Seismic Tractor - Units 2 and 3 i
- Insoection Scoce (71750)
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The inspectors observed Fire Protection personnel perform portions of Procedure SO23-XV 4.67, " Seismic Tractor, Pump, and Tanker Inspection,"
L Revision 2, Attachment 3, and discussed the performence with the manager, Site Emergency Preparedness, and the Security Manager.
'< Observations and Findinas
4 On August 25,1997, during the performance of Procedure SO23 XV-4.67, the
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inspectors observed a fire fighter exit a seismic tractor (a semitractor with a pump-mounted on it), leaving the engine running and the driver side door open. The fire
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fighter climbed on top of a nearby tanker approximately 30 feet away to open a
cover in preparation to perform the surveillance. The inspectors questioned the fire i
fighter about the security of the seismic tractor. The fire fighter indicated that it
was within security guidelines to leave the seismic tractor running with the door
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open.
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Subsequently, the inspectors questioned Security about the Fire Department personnel practice of leaving the seismic tractor running and having the fire fighter 30 feet away on top of a tanker. Security indicated that the practice was not acceptable and initiated an investigation into the event. Security Procedure SO123 IV 4.4, " Security Lock and Key Control." Revision 3, Attachment 6, Step C.1, required, in cart, that operators shall disable a vehicle with a vehicle locking device when the vehicle is not operator occupied inside the protected are The fire fighter left a seismic tractor running with the driver side door open and climbed on top of an unattached tanker approximately 30 feet away and failed to disable the vehicle with a vehicle locking device while inside the protected are The f ailure to follow Procedure SO123-IV-4.4 was a violation of TS 5.5.1. (Violation 361;362/97019-05).
The licensee initiated an AR to evaluate the event. The licensee identified that the communication between Security and the Fire Department concerning the requirement to maintain security of the seismic tractor was weak in that the fire fighters understood the practice they had been performing was acceptabl Security planned to evaluate the practice of disabling vehicles with vehicle locking devices when the vehicle is unoccupied, in addition, the Fire Department trained all fire-fighters on the importance of procedural compliance end emphasized the personal responsibility of understanding requirements and following the Conclusions A violation was identified by the inspectors as a result of not disabling an unoccupied vehicle inside the protected area. Communications between Security and the Fire Department were weak, in that the security requirement to disable an unoccupied vehicle was not understood by Fice Department personne S3 Security and Safeguards Procedures and Documentation S3.1 Incorrect Procedure Revision Used by Security - Units 2 and 3 Insocction Scope (71750)
The inspectors reviewed Procedure SO123-IV-4.4, " Security Lock and Key Control,"
used by Security to track security locking device keys issued, Observations and Findinos During followup of the August 25,1997, event in which the Fire Department failed to properly secure an unoccupied vehicle, the inspectors reviewed the security locking device key issue log and identified that Security was using an old revision of Procedure SO123 IV-4.4. Security used Revision 1, TCN 1-6 and the current procedure was Revision 3, which became effective on August 15,1997. The inspectors informed Security about the discrepancy. The licensee initiated an AR as a result of the discrepancy and planned to further evaluate the use of out-of-date
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forms by Security. The inspectors found the licensee's corrective actions appropriate.
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Procedure SO123-IV-4.4, Step 3.1 requires, in 'part, to verify that the revision and
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any issued TCNs are current before using the docume.it. The failure of Security to l follow Procedure SO123 IV-4.4 is a violation of TS. This failure constitutes a
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' violation of minor significance and is being treated as noncited violation, consistent
with Section IV of the NRC Enforcement Poliev (NCV 361; 362/97019-06). Conclusions A noncited violation was identified by the inspectors as a result of security using an incorrect revision of Procedure SO123-IV-4.4. Security department personnel J- displayed inattention to detail by not ensuring that the procedure used for issuance i of log keys was current.
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V. Manaaenient Meetinas X1 Exit Meeting Summary
- The inspectors presented the inspection results to members of licensee management j at the exit meeting on October 1,1997. The licensee acknowledged the findings l presente The inspectors asked the licensee whether any materials examined during the f
inspection should be considered proprietary. ..No proprietary information was
! identified.
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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee D. Brieg, Manager, Station Technical J. Clark, Manager, Chemistry N. El-Akily, Stress Engineer, Nuclear Engineering Design Organization J. Fee, Manager, Maintenance G. Gibson, Manager, Compliance D. Herbst, Manager, Site Quality Assurance
[ T. Herring, Manager, Procurement Engineering R. Krieger, Vice President, Nuclear Generation J. Larson, Supervisor, Procurement Quality, Nuclear Oversight Division l J. Madigan, Manager, Health Physics (Acting)
H. Newton, Manager, Site Support Services D. Nunn, Vice President, Engineering and Technical Services T. Pierno, inservice inspection Engineer, dtation Technical Support H. Schutter, Stress Engineer, independent Safety Engineering Group K. Slagle, Manager, Nuclear Oversight Division W. Strom, Supervisor, independent Safety Engineering Group 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 90712: In-Office LER Review IP 92700: On Site LER Review IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support
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ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50-361;362/97019-02 IFl Effects of control room painting on CREACUS units 50-361/97019 03 VIO Inadequate procurement of steam generator primary manway cover gaskets 50 361/97019-04 IFl Laboratory testing of the correlation between steam generator manways hydraulic tensioner preload and actual torqu ;362/97019 05 VIO Seismic tractor not secured in accordance with procedures Opened and Closed 50 362/97019-01 NCV Electrical test equipment not seismically secured 50 361;362/97019-06 NCV Security use of out-of-date procedure i Closed 50 361;362/96011-02 IFl Charging pump seal water power supply (UFSAR error)
50-361/97005-04 URI Procurement and use of faulty SG manway gasket 50-361;362/97012 10 IFl Acceptability of locker room not being defined as a radiologically controlled area 50-361/97-009-00 -LER Class 1E 125 VDC battery surveillance 50-361;362/97-010-00 LER Charging subsystem check valve failure 50-361;362/97-010-01 LER Charging subsystem check valve failure Discussed 50-361;362/97012-07 URI Charging system check valve failures i
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LIST OF ACRONYMS USED AR action request -
CA- contaminated area CCW- component cooling water CE Combustion Engineering CP core protection calculator CREACUS control room emergency air cleanup system ECU emergency cooling unit ;
EDG emergency diesel generator LER licensee event report NCR nonconformance report OEM original equipment manufacturer OES originial equipment supplier PDR Public Document Room RP radiological protection SR surveillance requirement TCN temporary thange notice TS Technical Specification