IR 05000361/1999004

Insp Repts 50-361/99-04 & 50-362/99-04 on 990221-0403.Three Violations Noted & Being Treated as non-cited Violations. Major Areas Inspected:Aspects of Licensee Operations,Maint, Engineering & Plant Support

ML20206B503
Person / Time
Site:	San Onofre
Issue date:	04/20/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20206B494	List: IR 05000361/1999004 ML20206B492
References
50-361-99-04, 50-361-99-4, 50-362-99-04, 50-362-99-4, NUDOCS 9904290265
Download: ML20206B503 (23)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-361 50-362 License Nos.: NPF-10 NPF-15 Report No.: 50-361/99-04 50-362/99-04 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: February 21 through April 3,1999 Inspectors: J. A. Sloan, Senior Resident inspector, San Onofre J. G. Kramer, Resident inspector, San Onofre D. L. Proulx, Senior Resident inspector, Diablo Canyon J. F. Melfi, Project Engineer Approved By: L. J. Smith, Chief, Project Branch E, Division of Reactor Projects ATTACHMENT: Supplemental Information l

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EXECUTIVE SUMMARY

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San Onofre Nuclear Generating Station, Units 2 and 3 NRC Inspection Report No. 50-361/99-04; 50-362/99-04 j

- This routine, announced inspection included aspects of licensee operations, maintenance, engineering, and plant support. This report covers a 6-week period of resident inspectio Operatens

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• A noncited violation (Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Criterion V, was identified as the result of the failure of the licensee to have appropriate instructions for the control of the 4.16 kV and 480 V safety related bus voltag Operators, when raising the main generator voltage, increased the vital 4.16 kV bus

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voltage beyond a previously analyzed limit. With the 4.16 kV bus voltage already high, operators then paralleled an emergency diesel generator (EDG) to the bus and further raised its voltage. The licensee ultimately determined that the overvoltage condition on the busses was acceptable.- This was in the licensee's corrective action program as Action Request (AR) 981100296 (Section O1.2).

• Operator performance during the Unit 2 reactor startup was excellent. Operators used formal communications. Appropriate guidance was provided by Operations supervision and Reactor Engineering. Unnecessary distractions were kept to a minimum (Section 01.3).

• Operators carefully conducted midioop operations during the Unit 3 refueling outag Management oversight of the evolutions was excellent (Secton O1.4).

• The inspectors reviewed the report of the Institute of Nuclear Power Operations (INPO)

evaluation of the San Onofre facility performed in June 1998. The NRC review was performed to determine if the INPO evaluation results identify safety or training issues not previously identified by NRC evaluations. No additional NRC followup is planned (Section 07.1).

Maintenance

• Maintenance personnel performance during the removal of an EDG generator cylinder power assembly was excellent. The personnel used excellent foreign material exclusion practices. The personnel were very knowledgeable about the equipment and maintenance activities (Section M1.3).

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• Although Unit 2 containment material condition was acceptable for Mode 4 entry, minor material condition deficiencies were identified by the inspectors and properly addressed by the licensee (Section M2.1).

• The inspectors identified some small openings in the top cover of both trains of the containment emergency sumps in Unit 2 and a gap between the side screens and the top cover in both sumps in both units. An unresolved item was opened to review the licensee's evaluation of the relevant design requirements (Section M2.2).

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A noncited violation (NRC Enforcement Policy, Appendix C) of Technical Specification (TS) Surveillance Requirements 3.9.4.1 and 3.9.5.1 was identified for failure to adequately monitor shutdown cooling flow. The licensee identified that the total loop uncertainty (TLU) of the instrumentation used to perform these surveillances invalidated previous surveillance test results. This was in the licensee's corrective action program as AR 981000837 (Section M8.1).

Engineering

The licensee's identification, determination of cause, and planned and completed corrective actions, related to a design flaw in the component cooling water (CCW)

noncritical loop isolation valve actuators, demonstrated excellence in the support of the system by the current engineering organization (Section E2.1).

An unresolved item was opened to assess the licensees' reportability evaluation for a condition outside the design basis of the facility. In 1995, the licensee identified that the refueling water storage tank (RWST) outlet valves in both trains in Unit 3 could not be closed because of their degraded material condition. The NRC staff recently determined that the ability to close the valves was part of the design basis and performed an important redundant containment boundary function, when the ECCS pumps are not running during the course of an accident. This item is unresolved to give the licensee an opportunity to provide their perspective on the NRC staff's determination prior to NRC making a final determination regarding whether a violation occurred (Section E8.1).

The licensee performed additional evaluations and determined that the Train A control room emergency air cleanup system had not been inoperable as the result cf insufficient cable ampacity. The licensee's initial action to declare the system inoperable and to take corrective measures, although appropriate at the time, proved to be conservative (Section E8.2).

A noncited violation (NRC Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Criterion lil, " Design Control," resulted from the licensee's identification that the feeder cables from the Unit 3 unit auxiliary transformer to the Class 1E 4.16 kV busses could exceed the maximum allowable conductor temperature during backfeeding conditions. This was in the licensee's corrective action program as AR 980300480 (Section E8.3).

Plant Supoo_r1

The licensee's declaration of an Alert and response to a potential explosive device (pipe bomb) were conservative. Licensee performance in the technical support center was good and included appropriate personnel, communications, and briefings. The licensee's assessment of the event was self-critical (Section P1.1).

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Report Details Summary of Plant Status Unit 2 began this inspection period in Mode 4 in Day 50 of the Unit 2 Cycle 10 refueling outage and reached Mode 3 on February 22,1999. The unit reached Mode 1 on February 25 and was synchronized to the grid on February 26. The unit reached essentially full operating power on February 28,1999, and operated at full power through the end of this inspection perio Unit 3 began this inspection period operating at essentially full reactor power. On March 27,1999, the unit was shut down to begin the Unit 3 Cycle 10 refueling outage. On March 28 the unit entered Mode 5, and this inspection period ended with Unit 3 operating in Mode 6 with the core fully loade . Operations 01 Conduct of Operations I

01.1 General Comments (71707)

The inspectors observed routine and nonroutine operational activities throughout this inspection period. Some of the activities observed included:

Response to boron concentration "hi/lo" annunciator (Unit 2)

Reset boron concentration alarm limits (Unit 2)

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Set control element assembly calculator inoperable flags on the core protection calculator system (Unit 2) '

Heat treatment of the circulating water system (Unit 3)

Response to area radiation instrument failure (Unit 3)

Start Train A CCW and saltwater cooling pumps (Unit 3)

Shift turnovers (Units 2 and 3) ]

• Outage tumovers (Units 2 and 3)

Operators were thorough and methodical in preparing for and conducting routine ;

evolutions. Close management and supervisory oversight of operational activities were l evident. Procedure use and operator communications were consistent with written licensee management expectations. Specific comments on activities are discussed !

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-2-l 01.2 4.16 kV Bus Overvoltaae - Unit 2 Insoection Scope (37551. 71707)  ;

The inspectors observed operator response to a request from the Generation '

Operations Center to raise switchyard voltage. The inspectors reviewed l Procedures SO23-3-3.23, " Diesel Generator Monthly Test," Revision 14; SO23-6-20,

" Main Generator Voltage Regulator Operation," Revision 6; and AR 981100296. The inspectors discussed the event with Operations management and the supervisor, Electrical Systems and Analysi Observations and Findinos I

On November 4,1998, the Generation Operations Center requested that operators raise I the grid voltage as high as allowable because of the loss of a 500 kV line between California and Arizona. At approximately 11:30 a.m., operators raised the switchyard voltage by increasing both units' generator output voltage. The inspectors subsequently questioned the shift manager regarding any limits on raising voltage. The shift manager ,

indicated that there were two limits, one being the main generator capabilities curve and l the other being a limit of 530 volts on the vital load centers. In this case, the load center I voltage limit was the most restricting valu Because of the inoperability of the Train A Emergency Diesel Generator (EDG) 2G002, operators performed an 8-hour ac sources verification, in accordance with Procedure SO23-3-3.23. During performance of the verification, the operators identified j that the voltage on the Train B 4 kV Bus 2A06 was 4.58 kV, which was greater than the maximum allowable voltage (4575 volts) specified in the ac sources verification. The i operators lowered the main generator output voltage to get Bus 2A06 voltage within specificatio The inspectors retrieved a computer-generated trend of the 4 kV bus voltages for that day. The inspectors observed that the voltage on Unit 2 Train A 4 kV Bus 2A04 had averaged approximately 4.59 kV and peaked at 4.66 kV when the EDG was paralleled i to the bus. The inspectors identified that, during tha EDG test, Procedure SO23-3-3.23, Attachment 1, step 2.4.11, required operators to adjust the positive var loading until one i of several criteria was met. One of the criteria was 4.53 kV to 4.55 kV bus voltage. At !

the time the EDG was loaded to the bus, the bus voltage was already above the voltage j limit at approximately 4.60 kV. The operators continued to raise voitage to approximately 4.66 kV. The operators did not notice that the voltage was above the bus i voltage criteria before they started the voltage increase and, therefore, never entered the criteria and did not observe the abnormally high bus voltag The licensee initiated AR 981100296 to document the event. The corrective actions included required reading for the operators that described the event. The AR included an assignment to evaluate providing guidance to operators to monitor the 4.16 kV and 480 V busses when adjusting main generator voltage and another assignment to evaluate the effect of the overvoltage condition on the busse I l

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3-The inspectors discussed the overvoltage condition on the busses with the license The licensee determined that the high voltage on the 4.16 kV bus would increase the postulated fault currents at the 4.16 kV bus,480 V load center, and 480 V motor-control centers supplied by the 4.16 kV bus. The calculation assumed that a short circuit occurred at each individual bus that resulted from essentially bolting all three phases together at the bus. The 4.16 kV bus was capable of interrupting the fault current in this configuration; the load centers and motor-control centers were not. However, the licensee assumed that the three-phase bolted faults in the switchgear were not credible events and calculated that the interrupting ratings of the breakers were greater than the maximum three-phase bolted fault current resulting from faults outside the Class 1E switchgear roo ,

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The inspectors reviewed the licensee's calculations and observed that one of the factors that determined fault current was the impedance of the load cable. The inspectors identified that inconsistencies in the cable length used to calculate impedance could result in an unacceptable fault interruption capability. The licensee corrected the ,

discrepancies in the calculation. The inspectors performed a walkdown of the cable '

length of the most restrictive cables assumed in the calculation and concluded thct the ,

licensee used conservative values for cable lengt l l

Inadequate instructions for the control of the 4.16 kV and 480 V bus voltages while raising the main generator voltage regulator resulted in the busses exceeding a previously analyzed voltage limit. This condition was further exacerbated when operators paralleled an EDG to the 4.16 kV bus and further raised the voltag CFR Part 50, Appendix B, Criterien V, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. The failure of the licensee to have appropriate j instructions on the control of 4.16 kV and 480 V bus voltage was a violation of 10 CFR Part 50, Appendix B, Criterion V (NCV 361/99004-01). This Severity LevelIV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation was in the licensee's corrective action program as AR 98110029 c. Conclusions A noncited violation (Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Criterion V, was identified as the result of the failure of the licensee to have appropriate instructions for the control of the 4.16 kV and 480 V safety-related bus voltag Operators, when raising the main generator voltage, increased the vital 4.16 kV bus voltage beyond a previously analyzed limit. With the 4.16 kV bus voltage already high, operators then paralleled an EDG to the bus and further raised its voltage. The licensee ultimately determined that the overvoltage condition on the busses was acceptabl l l

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O1.3 Reactor Startuo - Unit 2 Inspection Scope (37551. 71707)

The inspectors observed the Unit 2 preparations for, and conduct of, the reactor startup at the end of the Unit 2 Cycle 10 refueling outage. The inspectors reviewed Procedures S023-3-1.1, " Reactor Startup," Revision 20; and SO23-5-1.3.1, " Plant Startup From Hot Standby to Minimum Load," Revision 1 Observations and Findings On February 23,1999, the inspectors observed operators pedorm a reactor startup projob briefing. The briefirtg included a discussion of the precautions of the startup

. procedure and the need for conservative decision making. A dedicated licensed operator performed the reactivity man;pulations and was supervised by a dedicated senior reactor operator.. Inverse count rate ratio (1/M) plots were independently pedormed by Operations and Reactor Engineering and were compared and discussed before the next control element assembly withdrawal. Good equipment performance and minimal outside activities during the startup resulted in negligible distractions to the cre Conclusions

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Operator performance during the Unit 2 reactor startup was excellent. Operators used formal communications. Appropriate guidance was provided by Operations supervision and Reactor Engineering. Unnecessary distractions were kept to a minimu .4 ~ Midloop Operatens - Unit 3 Insoection Scope (37551. 71707) '

The inspectors observed the preparations for, and conduct of, midloop operations on March 29-31,1999. The inspectors reviewed Procedure SO23-3-1.8, " Draining the

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- Reactor Coolant System," Revision 14; and Procedure SO23-5-1.8.1, " Shutdown Nuclear Safety," Revision Observations and Findings The inspectors attended the prejob briefing. The briefing included all aspects required by Procedure SO23-3-1.8, Attachment 1, step 1.39. During the briefing, a dedicated i

, board monitor (operator) maintained awareness of plant activities to allow the other crew members to focus on the briefin l i

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5-Throughout the evolution, the operators used the draindown level monitoring system (DLMS), heated junction thermocouples (two trains), the refueling water level indicator (narrow- and wide-range), and the sight glass to monitor vessel level. In ,

addition, operators monitored indiract indications, such as inventory changes in the

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radwaste primary tanks that were aligned to receive the water from the reactor coolant r.ystem (RCS). The inspectors verified that the level indications were within procedurally-required tolerances prior to the draindow The draindown commenced on March 29 at 11:18 p.m. The licensee had established a minimum time-to-boillimit of 16 minutes and closely monitored the calculated time-to-boil for the RCS. During the draining evolution, the inspectors calculated the time-to-boil and verified that the licensee calculations were accurate. Reduced inventory conditions were exited at 6:20 p.m. on March 31, after the installation of the steam generator nozzle dams and completion of an inspection of Reactor Coolant Pump 3P00 Operations management representatives continuously and closely monitored the draindown and subsequent midloop operations until the reduced inventory condition was exite I On March 31, the critical functions monitoring system computer locked. This caused a loss of the DLMS indication in the control room. The loss occurred prior to the filling of the RCS with conditions stable at midloop. The operators responded to the loss of indication by performing appropriate compensatory measures. During the fill of the RCS, the DLMS was made functional for control room level indication. This was the second time the DLMS was lost for several hours in a reduced inventory condition this year. The previous example was documented in NRC Inspection Report 50-361; 362/99-0 Conclusions Operators carefully conducted midloop operations during the Unit 3 refueling outag I Management oversight of the evolutions was excellen Quality Assurance in Operations j 07.1 Institute of Nuclear Power Operations Evaluation (71707)

The inspectors reviewed the report of the Institute of Nuclear Power Operations ;

evaluation of the San Onofre facility that was performed in June 1998. The purpose of ;

the review was to determine if the INPO evalu.dion results identify safety or training '

issues not previously identified by NRC evaluations, which are significant enough to require NRC followup. No additional NRC fodowup is planne r 1

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6-08 Miscellaneous Operations issues (92700)

0 (Closed) LER 362/1999-001-00: entry into TS 3.0.3, due to both emergency chilled water (ECW) trains being inoperabl On February 11,1999, Unit 3 opetators had declared the Unit 3 Train A CCW inoperable because of the inoperability of the noncriticalloop isolation valves and the noncritical loopaligned to Train A. Since the ECW Train A was aligned to the Unit 3 CCW Train A, it was also inoperable.-

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At 7:18 a.m., ECW Train B was declared inoperable when CCW Train B fell below the minimum temperature (55'F) to support ECW operability because of low ocean )

temperature. With two trains of ECW inoperable, Unit 3 entered TS 3.0.3. ECW is a shared system between the two units. The ECW TS did not apply to Unit 2, since Unit 2 ;

was in Mode 6. . At 8 a.m., the noncritical loop was transferred to Train B and the TS 3. action statement was exited, since the CCW temperature on Train A was greater than 55'F-At 8:45 a.m., Unit 3 re-entered TS 3.0.3 when Train A CCW temperature fell below 55'F and Train B was inoperable because of the noncriticalloop being aligned to Train l At 9:20 a.m., TS 3.0.3 was exited when ECW Train A was aligned to an operable Unit 2 CCW Train A that was above 55' To resolve the low ocean temperature's effect on the CCW temperature, the licensee established partial recirculation flow in the circulating water system. The licensee also initiated AR 990200865 to document the evaluation and resolution of the conditio . Maintenance M1 Conduct of Maintenance -

M1.1 fa9DeralComments Inspection Scope (62707)

The inspectors observed all or portions of the following work activities: I

Qualified safety parameters display system Channel A Heated Junction Thermocouple 2A repair (Unit 3)

Modification of electrical panel for Train A EDG 3G002 emergency supply fan to improve monitoring for engineered safety features testing (Unit 3) l

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7- Observations and Findinas The inspectofis fodnd the worliperforifiedisnder these activities to be thorough. All work observed was performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure.- When applicable, appropriate radiation controls were in plac !

In addition, see the specific discussions of maintenance observed under Section M1.3,

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The inspectors observed all or portions of the following surveillance activities:

Auxiliary feedwater pump flow verification (Unit 2)

Excore neutron monitor Safety Channel B channel calibration (Unit 3) Observations and Findinos  ;

The inspectors found all surveillances performed under these activities to be timroug All surveillances obscrved 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 qual;ty control personnel were present whenever required by procedure. When applicable, appropriate radiation controls were in plac M1.3 EDG Repairs - Unit 2 Inspection Scope (62707)

I The inspectors observed maintenance on the Tiain B EDG 2G003. The inspectors '

reviewed Procedure SO23-1-8.76, " Emergency Diesel Generator Overhaul," Revision 2; Procedure SO123-1-1.18, " Foreign Material Exclusion (FME) Control," Revision 4; and Maintenance Order 99030265. The inspectors discussed the activity with Maintenance personne Observations and Findinas l

On March 9,1999, the inspectors observed Maintenance personnel perform removal of i an EDG cylinder power assembly. The technicians properly secured tools, equipment, and personal items to ensure compliance with foreign material exclusion. The ]

technicians consistently used the overhaul procedure during the assembly removal. The technician's communications included repeat backs. Technicians and supervisors demonstrated good knowledge of the maintenance activitie l l

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-8- Conclusions Maintenance personnel performance during the removal of an EDG cylinder power assembly was excellent. The personnel used excellent foreign material exclusion practices. The personnel were very knowledgeable about the equipment and maintenance activit M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Containment Matenal Condition - Unit 2 Inapochon Scope (62707)

The inspectors performed a walkdown of the Unit 2 containment and discussed the identified deficiencies with outage managemen Observations and Findinas On February 19,1999, the inspectors performed a walkdown of the Unit 2 containment j prior to the unit entering Mode 4. The inspectors identified several r:iaterial condition discrepancie The inspectors observed that the polar crane trolley was not parked at the prescribed mark on the bridge, but was parked approximately 4 feet closer to the center of containment. The licensee initiated AR 990201675 to evaluate the position. The licensee determined that an acceptable park position is 2.5 feet from the current park sign towards the containment wall to 5.25 feet towards the containment center; therefore, the trolley was parked in an acceptable pcaition. However, the licensee planned to -

change the drawing that showed the position of the park sign to better reflect the desired positio ,

The inspectors observed loose and slightly damaged insulation on Reactor Coolant

' Pump 2P002. The licencee initiated AR 990201670 as a result of the inspectors' findin The licensee initiated a maintenance order and repaired and fastened the insulation the same day. The inspectors concluded that the licensett's corrective actions were acceptabl l The inspectors observed a frayed fiberglass sheath on the cable from the Pressurizer Safety Valve 2PSV0201 accelerometer. The licences initiated AR 990201678 to evaluate the condition. A station technical engineer performed a walkdown of the cable and determined that the sheath around the wire had some fraying. However, the stainless steelJacket on the wire and the wire itself were not damaged. The engineer inspected the other pressurizer safety valve accelerometer cable and found it to be i

. satisfactory. The engineer concluded that there were no operability concerns and that

- the sheath was not required for environmental qualification or other design reasons. The licensee determined that the sheath continued to meet its function of providing isolation from mechanical wear. The licensee decided not to repair the deficienc !

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-9- Conclusions Although Unit 2 containment material was acceptable for Mode 4 entry, material condition deficiencies were identified by the inspectors and properly addressed by the license M2.2 Contamment Emergency Sumos - Units 2 and 3 The inspectors performed a walkdown of the Units 2 and 3 containment emergency -

sumps and discussed the identified deficiencies with outage management. The inspectors reviewed.AR 990201682, Updated Final Safety Analysis Report (UFSAR)

Section 6.2, Regulatory Guide 1.82, " Sump for Emergency Core Cooling and

Containment Spray Systems," Maintenance Order 99031007, NRC Inspection Reports 50-361; 362/93-38 and 50-361; 362/94-02, and LER 361; 362/1993-0104 Observations and Findings On February 19,1999, the inspectors observed deficiencies in both trains of the Unit 2 containment emergency sumps. The inspectors observed two gaps on the top plate, with the largest being approximately 3/8 inch by 3 inches. In addition, the inspectors observed a 1/4-inch gap at the top of the sump where the fine mesh was attached to the sump.' The licensee initiated AR 990201682 to evaluate the condition. The licensee initiated repairs to the top plate but did not repair the 1/4-inch gap above the fine mesh in the sump. The licensee performed an operability assessment and determined that the sumps were operable with the 1/4-inch ga On March 30, the inspectors performed a walkdown of the Unit 3 containment '

emergency sumps and observed that the sumps did not have the similar gaps in the top plate as Unit 2. However, both trains of sumps had the similar 1/4-inch gap at the top of the sump where the fine mesh was attached to the sum The containment sumps were described in USFAR Section 6.2.2.1.2.5 and Figure 6.2-5 The UFSAR described the sump as having a mesh size of 0.090 inches, based on the minimum core channel opening through which the safety injection system must pump. In addition, the UFSAR, Appendix 3A, Section 3A.1.82, indicated that the sump design is consistent with the recommendations of Regulatory Guide 1.82, Revision 0, except for the differences indicated in Table 3A-2. Regulatory Guide 1.82 described the sump as being protected by a fine inner screen. Regulatory Guide 1.82 further specified that the

- size of the openings in the fine screen should be based on the minimum restriction in systems served by the sump, and UFSAR Table 3A-2 did not describe any deviations from Regulatory Guide 1.82 relative to that aspect of the configuratio The licensee had previously taken corrective action to close gaps in the cover plate that had beer, identified in 1993 (NRC Inspection Report 50-361; 362/93-38 and LER 361; 362/1993-010-00). The corrective actions from that occurrence had not completely resolved the deficiencies in the Unit 2 cover plate and were therefore inadequate. However, the gap over the top of the mesh on the sides of the sumps had not previously been identified as a deficienc r

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-10-The acceptability of the licensee's actions will be reviewed as an unresolved item pending review of the licensee's evaluation of the design requirements (URI 361; 362/99004-02). Conclusions The inspectors identified some small openings in the top cover of both trains of the containment emergency sumps in Unit 2 and a gap between the side screens and the top cover in both sumps in both units. An unresolved item was opened to review the licensee's evaluation of the relevant design requirement M8 Miscellaneous Maintenance issues (92700) J M8.1 (Closed) LER 361:362/1998-022-00: shutdown cooling system (SDC) inoperable because of inadequate surveillance tes This LER discussed an event in which the licensee determined that TS Surveillance Requirements 3.9.4.1 and 3.9.5.1 were not met because of instrument uncertainty that had invalidated previous surveillance test The licensee initiated a program to determine the TLU of !nstrumentation that was used to verify surveillances. This program identified that the ir&:ated SDC flow uncertainty was approximately 1340 gpm. During reduced inventory conditions, operators normally adjusted SDC flow to an indicated value of 2300 gpm. However, TS 3.9.4 and 3. require a minimum flow of 2200 gpm. Given the uncertainty of the instrumentation used to verify minimum SDC flow, the licensee assumed that SDC flow could have been as low as 960 gpm, in violation of the TS. Units 2 and 3 were in Mode 1 when this condition was discovered and TS 3.9.4 and 3.9.5 were not applicable in Mode 1. The licensee -

planned to perform the surveillances when they reached the applicable plant condition For corrective actions, the licensee revised Procedure SO23-3-3.25.1, "Once a Shift Surveillance (Modes 5 and 6)," Revision 22, to require SDC flow to be measured locally using high accuracy measuring and test equipment when verifying minimum flow to meet ;

the TS. The inspectors reviewed Procedure SO23-3-3.25.1 and concluded that the i procedure revision adequately addressed the issues of this LE l l

In addition, the inspectors reviewed the scope and performance of Engineering with !

respect to the TLU program. The inspectors noted that the TLU program was a j broad-based pregram that revised numerous calculations in many safety-related -

systems. All of the required calculations were completed, but a number of corrective actions coming out of the calculations were in progress at the end of this inspection period. The inspectors concluded that the overall licensee effort, with respect to TLU i

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concems, was satisfactor l

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The failure to perform an' adequate surveillance of SDC flow is a violation of

' TS Surveillance Requirements.3.9.4.1 and 3.9.5.1. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation was in the licensee's corrective action program as

AR 981000837 (NCV 361; 362/99004-03).

Ill. Engineering E2 - Engineering Support of Focilities and Equipment E CCW Noncritical Loon Isolation Valve A+= tar Desian - Units 2 and 3 Inspection Scope (37551)

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The inspectors reviewed the licensee's efforts to identify and resolve a newly-identified problem regarding the inability of the CCW noncritical loop isolation valves to close under design basis conditions. The inspectors reviewed AR 990200839, discussed the actuator I design and proposed changes (including testing) with 'the licensee, and walked down the modifications made to the actuator Observations and Findinas The safety function of the valves was to close in order to isolate the Class 1E seismically-qualified CCW loops from the nonseismically-qualified noncritical loop. The valves were air operated, but neither the air supply nor the nitrogen backup supply were seismically qualified, so surveillance testing relied on seismically-qualified emergency air accumulators to supply the motive force to close the valves. Either CCW loop could be aligned to supply the noncritical loop, and the noncritical loop was necessary to be in service during normal plant power operation In 1998, the licensee recognized that the noncritical loop isolation valves were required to close within 2 seconds of each other in order to prevent a potential water hammer condition. This was determined as part of the licensee's actions in response to NRC Generic Letter 96-06," Assurance of Equipment Operability and Containment Integrity

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During Design-basis Accident Conditions."

During the Cycle 10 refueling outage, the licensee realized that the 2-second criterion also needed to be satisfied when the valves were closed using the emergency accumulators only and tested the valves with the normal air and nitrogen supplies isolated to confirm that the criterion was met. The valves did not respond as expected, and the results were inconsistent. Ultimately, the licensee determined that the test J equipment (temporary pressure sensors and tubing that supported the air-operated valve testing) influenced the results, in that the valves would not always close when the test equipment was disconnected, but would close when the test equipment was connecte p 1

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-12-The licensee determined that isolating the air and nitrogen supplies trapped a volume of air in the pilot valve and connected tubing that would normally be vented during the closing cycle. Instead, the air on the pilot valve, originally at 80 psig, expanded into a short unpressurized section of tubing, resulting in about 40 psig air pressure remaining on one side of the piston in the pilot valve. The pressure from the emergency air accumulator (80 psig), in conjunction with the lower piston surface area on the side of the piston that this air acted on, did not result in sufficient differential pressure to lift the ,

piston and thus port the air from the emergency air accumulator to the valve actuato I The licensee modified the design by adding an expansion chamber connected to the tubing such that the chamber that the trapped air expanded into was more than double !

This resulted in sufficient differential pressure to cause the piston to lift and for the valve to operate as intende The licensee determined that this unrecognized failure mode had been introduced when the backup nitrogen supply had been added in 1995. At that time, check valves in the air and nitrogen supply tubing had been installed. Prior to that modification, a seismic event {

i that damaged or disabled the air supply would have resulted in either a line break or a j large depressurized section of the air system. Either of these conditions would have provided a way for the air over the piston to escape, allowing the piston to function as designed. The check valves prevented the air from escaping and prevented l development of sufficient differential pressure across the pisto Upon discovery of the design flaw, the licensee declared the noncritical loop isolation valves in Unit 3 inoperable when open and entered the 72-hour shutdown action requirement of TS 3.7.7. The modification (addition of an expansion chamber) was first implemented on the Unit 3 Train A valves, and testing was satisfactorily complete Operators exited TS 3.7.7 after swapping the noncritical loop to Train A and closing the Train 3 valves. The modification was subsequently implemented on the Train B valves, and testing was completed except for stroke timing the valves after recoupling the actuators with the valves. The valves were determined to be operable while closed. The licensee subsequently completed the testing and declared the valves fully operable. The !

licensee implemented the expansion chamber modification and tested the valves in I Unit 2 prior to Mode 4 entry during the Cycle 10 refueling outag During past periods of operation with one CCW critical loop inoperable, a seismic event could have rendered the other critical loop inoperable, resulting in a loss of safety function. The licensee submitted LER 361; 362/1999-003-00 as a result of the design i flaw. The safety significance and potential enforcement for this issue will be evaluated during review of the LE ,

c. Conclusions The licensee's identification, determination of cause, and planned and completed corrective actions, related to a design flaw in the CCW nonentical loop isolation valve actuators, demonstrated excellence in the support of the system by the current engineering organization.

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-13-E8 Miscellaneous Engineering issues (92700,92903)

E Iglosed) Insoection Followuo item 362/95007-01: assessment of the safety significance of the RWST outlet valves failing to clos On May 31,1995, RWST Outlet Valve 3HV9300 had failed to close during testing. This followup item was created to assess the safety significance of RWST Outlet i Valves 3HV9300 and 3HV9301, Backaround ,

There are two RWSTs per unit with an outlet isolation valve (HV9300 or HV9301) and an outlet check valve (MU001 or MUOO2) located in the piping from the RWST to each ECCS train. During a loss of coolant accident, a recirculation actuation signal occurs at approximately 18 percent RWST level. The emergency sump isolation valves open automatically, the low pressure safety injection pumi s stop, and the long-term core cooling is initiated by recirculating the water in the containment sump by the high pressure safetw isjaction pumps. The operators are then directed by the emergency operating instructions to shut the RWST outlet valves from the control room when the recirculation actuation signalis initiated. The UFSAR, Section 6.3, and Figures 6.3-2 through 6.3-4 show the RWST outlet valves as shut during the water recirculation from sump mod Desian Basis Reauirements

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Section 6.3 of the UFSAR stated that the RWST motor-operated outlet isolation valves are manually closed for the recirculation mode after verification that the containment sump j discharge valves are open. Figures 6.3-2 through 6.3-4 for short- and long-term  ;

recirculation also showed the RWST outlet isolation valves to be in the closed positio '

The UFSAR explicitly stated that the operators will close the RWST isolation valves, and it i failed to state that closure of these valves is not required to meet the design basis for this l system. Therefore, the inspectors concluded that the RWST outlet isolation valves did not meet the design basis requirements as stated in the UFSA Emeraency Core Coolina Safety Function The NRC Office of Nuclear Reactor Regulation (NRR) staff evaluated whether or not closure of the RWST outlet isolation valves was needed for proper operation of the ECC The two cases evaluated were: (1) water draindown to the point at which adequate net positive suction head (NPSH) was unavailable to the injection pumps, and (2) backflow of water from the recirculation sumps into the RWST, which could impact the inventory of water needed for proper operation of the safety injection syste The potential for inadequate NPSH was thoroughly evaluated by NRR's Reactor Systems Branch and included confirmatory calculations of the available NPSH, assuming that the RWST isolation valves remain open. The Reactor Systems Branch evaluation concluded that aWquate NPSH would be assu ed for all cases, even though the water could be drained from the RWSTs if the isolation valves were assumed to remain ope r

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-14-The NRR staff evaluated the radiological consequences of having the RWST isolation valves open during a design basis event. The licensee documented its assessment of the issue in Calculation N04060-024, " Radiological Consequences of Valve Leakage Following a Loss of Coolant Acadent." A review of the calculation revealed that no credit for the RWST isolation valves was assumed; only the outlet check valves were credited for preventing backflow through the RWST piping. As stated above, the facility was licensed based on the assumption that failures of the check valves in the safety injection system are not considered credible. The value for backleakage through the outlet check valves assumed by the licensee was consistent with NRC staff guidelines contained in Standard Review Plan Section 15.6.5, Appendix B. The licensee's radiological analysis maximized the RWST water volume, since minimizing the RWST air volume would minimize dilution of radioactive material prior to release to the environment. The staff concurred with the licensee's determination that minimizing the RWST ait volume maximizes the radiological consequence In addition, the staff reviewed the impact on the radiological .,onsequences of draining the RWSTs and concluded that, as long as the outlet check valves remained submerged, )

the leak rate assumptions used in the licensee's anaWs would remain valid. The elevation of the subject check valves was comparxi to the minimum water level in the RWST piping, as calculated by the Reactor Svgems Branch. This comparison showed 1 that there would be at least 20 feet of water over the check valves at all time Therefore, the staff concluded that having the RWST isolation valves open does not )

affect the results of the licensee's radiological analysis and concurred with the licensee's determination that radiation levels were acceptabl However, the staff also noted that the inability of the RWST isolation valves to close upon a RAS causes operation to to degraded from its original design purpose because the water level in the RWST could be pumped down to the RWST exit line. The reduced water level did not agree with the assumption of a 18.5 percent, *3.8 percent RWST water level used in the radiological calculation. In addition, if the ECCS pumps are not running and there is no isolation between the sump and the RWST, the large containment accident pressure could push water (and containment gases) from the sump into the tank. The staff noted that this illustrates the importance of the two isolation valves to perform an important redundant containment boundary functio In summary, since the license basis documented in the UFSAR is based on the assumption that check valve failure is not credible, and the check valves were found to be functional at the time of the event, the ECCS function remained within the design basis for preventing water flow back to the RWST and the estimated radiological consequences remained acceptable. However, with the RWST isolation valves left open, the redundant containment boundary and the ability to prevent any leakage past the check valves and back to the RWST was degrade e. Reoortability in an August 13,1992, memorandum to file, the licensec documented an active failure exemption justification for the RWST outlet check valves. The operability assessments documented by the licensee in ARs 950300186 and 950500087, addressing the failure of I

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-15- l In summary, since the license basis documented in the UFSAR is based c the '  !

assumption that check valve failure is not credible, and the check valves were found to ,

be functional at the time of the event, the ECCS function remained within the design I basis for preventing water flow back to the RWST and the estimated raJiological consequences remained acceptable. However, with the RWST isolation valves left open, the redundan' containment boundary and the ability to prevent any leakege past the check valves nd back to the RWST was degrade Reportability

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in an August 13,1992, memorandum to file, the licensee documented an active failure i exemption justification for the RWST outlet check valves. The operability assessments i documented by the licensee in ARs 950300186 and 950500087, addressing the failure of ;

the Unit 3 RWST outlet isolation valves, extrapolated this exemption Justification to mean :

that the outlet check valves fully satisfied the design basis function of isolating the RWST !

after a recirculation actuation and that the outlet isolation valves had no design function and were not part of the design basis. The licensee determined in 1995 that the valve failures were not reportabl Based on the recent NRC staff's determination that the ability of the RWST outlet isolation valves to close is part of the design basis and that the RWST outlet isolation valves perform an important redundant containment boundary function when the ECCS pumps are not running during the course of an accident, the inspectors determined that the licensee may have been required to have reported the event in accordance with 10 CFR 50.73(a)(2)(ii)(B).

This issue is in the licensee's corrective action program as AR 990400496. Based on the additional information from the NRC staff, the licensee planned to reevaluate their original reportability determination. This item is unresolved to give the licensee an opportunity to provide their perspective on the NRC staff's determination prior to NRC making a final determination regarding whether a violation occurred (URI 362/99004-04).

E8.2 (Closed) Unresolved item 361: 362/99001-04: review of reportability assessment regarding control room emergency air cleanup system operabilit The inspectors reviewed the licensee's reportability assessment regarding the licensee's i determination that a cable for the Train A control room emergency air cleanup system I had insufficient ampacity while a Cerablanket fire barrier was installed over a section of the cable raceway. Subsequent review by Nuclear Engineering Design determined that environmental qualification testing had demonstrated that the aging factors for the cable in question were not as severe as had been assumed in the cable ampacity calculation Additionally, the ambient temperature of the room in which the cable was installed was, historically, significantly lower that had been assumed in the calculations. The licensee's subsequent evaluation concluded that the original configuration of the cable, with the Cerabianket installed, was adequate under all design conditions. The evaluation also considered the future aging of the cable to ensure that the cable would remain operable i

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-16-for the remainder of the facility license. The licensee's initial action to declare the system inoperable and to take corrective measures, although appropriate at the time, proved to be conservative. No noncompliance with NRC requirements was identifie E8.3 (Closed) LER 361: 362/1998-008-00: 4.16 kV supply cable exceeds ampacity ratin On March 6,1998, the licensee determined that the feeder cables from a unit auxiliary transformer to the Class 1E 4.16 kV buses for both Units 2 and 3 could exceed their maximum allowable conductor temperature when a unit is in the backfeed alignment, is supplying power to its shutdown loads, and is also providing power to the maximum postaccident loads in the other unit via the 4.16 kV bus crosstie. Subsequent calculations revealed that the Unit 2 ampacity was acceptable. However, Unit 3 would require a design change to correct the ampacity deficienc In the LER, the licensee stated that the cables would have been able to supply the maximum calculated amperage, in spite of exceeding the allowable temperature limit In addition, all connected loads would have been able to perform their intended function Based on the licensee's analysis, the inspectors concluded that there was negligible safety consquence associated with this condition and no actual safety consequenc To retum the Unit 3 feeder cables to an acceptable ampacity rating, the licensee implemented Field Change Notice F14774E. The field change notice removed sections of the top cable tray cover, providing greater heat dissipation of the feeder cables, and installed appropriate fire barriers on the Class 1E raceways that did not meet the required separation distances. The licensee completed the field change notice on March 15,199 The licensee determined that, under worst case loading conditions while backfeeding, the feeder cable temperatures could exceed the allowed 130'C and might not return to 90*C, or less, within the allowed 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />. This condition did not comply with the design information of UFSAR Section 8.3.1.1.3.10 CFR Part 50, Appendix B, Criterion lil, requires, in part, that measures shall be established to assure that the design basis is correctly translated into specifications, drawings, procedures, and instructions. The failure of the licensee to assure the design basis was correctly translated into specifications was a violation of 10 CFR Part 50, Appendix B, Criterion 11 This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 362/99004-05). This violation was in I the licensee's corrective action program as AR 98030048 l

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-17-IV. Plant Support P Conduct of Exampi+y4::: Activities P Alert Declared because of a 9WM Lookina Pine / Potential Bomb - Units 2 and 3 Inspection Scope (71750. 93702)

The inspectors monitored the licensee's performance during a declaration of an Aler The inspectors reviewed Procedure SO123-Vill-10, " Emergency Coordinator Duties,"

Revision 9, and Procedure SO123-Vill-1, " Recognition and Classification of Emergencies," Revision 11. The inspectors reviewed ARs 990300467,496,503,506, 509,597, and 99 Observations and Findinas On March 15,1999, at 10:15 a.m., the licensee declared an Alert because of a potential bomb that had been discovered in the protected area. The suspicious looking device was an approximately 12-inch long,2-inch diameter copper pipe that was capped on both ends and was discovered behind a large storage container on the turbine deck 70 feet elevation oy a contract employe The inspectors responded to the control room and then to the technical support cente The licensee activated the technical support, operations support, and emergency operations centers and performed an evacuation of local plant areas surrounding the device. Security contacted the United States Marine Corps Explosive Ordnance Disposal

. Team for assistance. The Explosive Ordnance Disposal Team x-rayed the device and ultimately determined that it was not a bomb. The event was terminated at 12:27 The licensee initiated several ARs, as a result of the event, to capture lessons-learned and areas for improvement. The inspector reviewed the ARs and concluded that the licensee's actions were self-critical, Conclusions The licensee's declaration of an Alert and response to a potential explosive device (pipe bomb) were conservative. Licensee performance in the technical support center was good and included appropriate personnel, communications, and briefings. The licensee's assessment of the event was self-critica V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the exit meeting on April 7,1999. The licensee acknowledged the findings presente The_ inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie r

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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee D. Brieg, Manager, Station Technical J. Fee, Manager, Maintenance D. Herbst, Manager, Site Quality Assurance ,

J. Hirsch, Manager, Chemistry I R. Krieger, Vice President, Nuclear Generation J. Madigan, Manager, Health Physics D. Nunn, Vice President, Engineering and Technical Services A. Scherer, Manager, Nuclear Regulatory Affairs R. Waldo, Manager, Operations

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INSPECTION PROCEDURES.USED IP 375S1: Onsite Engineering IP 61726: Surveillance Observations ,

IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92700: On Site LER Review 4 IP 92901: Followup - Plant Operations i IP 92903: Followup - Engineering IP 92904: Followup - Plant Support IP 93702: Prompt Response to Unplanned Events at Operating Power Reactors

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ITEMS OPENED AND CLOSED-w-361; 362/99004-02 URI containment emergency sump design requirements and corrective actions (Section M2.2).

- 362/99004-04 URI assessment of licensee's evaluation of whether to submit an ~

LER for RWST valve out of design basis (Section E8.1).

Opened and Closed

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361/99004-01 NCV failure to have appropriate instructions for control of 4.16 kV and 480 kV safety-related bus voltage (Section 01.2)

361;362/99004-03 NCV failure to perform an adequate surveillance of SDC flow (Section M8.1).

362/99004-05 NCV failure to ensure design basis was correctly translated into specifications (Section E8.3).

Closed 362/1999-001-00 LER TS 3.0.3 entry due to both ECW trains being inoperable (Section 08.1).

361;362/1998-022-00 LER SDC system inoperable because of inadequate surveillance test (Section M8.1).

362/95007-01 IFl assessment of the safety significance of the RWST outlet valves failing to close (Section E8.1).

361; 362/99001-04 URI review of reportability assessment regarding control room l emergency air cleanup system operability (Section E8.2).

361; 362/1998-008-00 LER 4.16 kV supply cable exceeds ampacity rating l I

(Section E8.3).

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3-LIST OF ACRONYMS USED AR action request CCW component cooling water CFR Code of Federal Regulations DLMS draindown level monitoring system ECCS emergency core cooling system ECW emergency chilled water EDG emergency diesel generator l

INPO Institute of Nuclear Power Operations J LER licensee event report NCV noncited violation .

NPSH net positive suction head NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation PDR Public Document Room RCS reactor coolant system RWST refueling water storage tank l SDC shutdown cooling TLU totalloop uncertainty i TS Technical Specification UFSAR Updated Fiaal Safety Analysis Report i

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