ML20129F636

Insp Repts 50-361/96-09 & 50-362/96-09 on 96088-0907. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20129F636
Person / Time
Site:	San Onofre
Issue date:	09/24/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20129F584	List: ML20129F580 ML20129F609 ML20129F636
References
50-361-96-09, 50-361-96-9, 50-362-96-09, 50-362-96-9, NUDOCS 9610020043
Download: ML20129F636 (26)

See also: IR 05000361/1996009

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ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-361

50-362

License Nos.: NPF-10

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NPF 16

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Report No.: 50-361/96-09

, 50-362/96-09

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Licensee: Southern California Edison Co.

Facility: San Onofre Nuclear Generating Station, Units 2 and 3

! Location: 5000 S. Pacific Coast Hwy.

4 San Clemente, California

Dates: July 28 through September 7,1996

Inspectors: J. A. Sloan, Senior Resident inspector

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J. J. Russell, Resident inspector

D. L. Solorio, Resident inspector

D. G.- Acker, Senior Project inspector, WCFO

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Approved By: D. F. Kirsch, Chief, Branch F

i Division of Reactor Projects

ATTACHMENTS:

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Attachment 1: Partial List of Persons Contacted

List of Inspection Procedures Used

. List of items Opened, Closed, and Discussed

List of Acronyms

9610020043 960924

PDR ADOCK 05000361

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EXECUTIVE SUMMARY

San Onofre Nuclear Generating Station, Units 2 and 3

NRC Inspection Report 50-361/96-09;50-362/96-09

Operations

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• Command and control of a Unit 3 downpower evolution, with the exception of one

dilution, were generally consistent with documented licensee management

expectations and procedures. Command and control of the dilution were adequate.

, Operator attention to indications was good (Section 01.1).

) * Operators responded promptly and effectively to a transient resulting from the stuck

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feedwater control valve during the Unit 3 downpower (Section 01.1).

• The licensee failed to declare Inverter 2YOO3 inoperable and to take the actions

specified by Technical Specification (TS) Limiting Condition for Operation (LCO)

3.8.7, as required by TS Surveillance Requirement (SR) 3.0.1, after the output

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voltage was identified as being outside the acceptance criteria for TS SR 3.8.7.1

(documented in the Operator Rounds System). This is a violation of TS SR 3.0.1

(Section 01.2).

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• Operations management focused on nuclear safety in not wanting to transfer the l

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inverter loads to the alternate source, which was less reliable, as long as the

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inverter was operable. Management considered the inverter operable based on the

judgment of the shift technical advisor (STA) and cognizant engineer (Section

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• A weakness in the performance of operator rounds was identified as the result of

. operators not identifying a 4-month old boric acid buildup in an easily accessible, 1

welllighted area. The inspector identified this condition, which was the result of a

crack in the letdown system piping (Section O2.1).  ;

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• An evaluated simulator scenario, conducted by the training staff, sufficiently )

exercised operator skills to allow effective evaluation of their performance.

Operators performed as expected, with no deficiencies observed by the inspector

(Section 05.1).

Maintenance

• The licensee determined that the Operator Rounds System, used to accomplish a

weekly surveillance test, was not appropriate for the circumstances, in that the

acceptance criteria were not clearly understood as being acceptance criteria, and

the instrument used, in conjunction with the acceptance criteria, did not have the

required accuracy to confirm that the voltage was within the design range. This

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licensee-identified and corrected violation is being treated as a noncited violation

(Section 01.2).

Minor material deficiencies were generally being identified by the licensee, although

some were not. The increase in the number of inspector-identified deficiencies

indicates a slight negative trend in material condition. However, the overall material

condition, with respect to boric acid leaks, was very good and was being

well-managed (Section M2.1).

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The inspector identified that one value in a completed surveillance test for nuclear

instrument subchannel amplifier gains was not within the acceptance criteria. This

observation had no safety consequence since the gain was actually satisfactory and

the technician had mistakenly recorded an in-specification parameter as out of

specification. The instrumentation and controls (l&C) technicians, in this instance,

demonstrated inattentivn to detail by recording a meter reading erroneously

(Section M3.2).

• The licensee identified that a reactor coolant system (RCS) iodine analysis SR had

been missed as the result of operators' failure to identify that reactor power had

changed more than 15 percent in one hour during a downpower evolution in Unit 3.

This licensee-identified and corrected violation is being treated as a noncited

violation (Section M8.1).

Enaineerina

The operability assessment documented in Action Request (AR) 960801065

provided some assurance that the loads on inverter 2YOO3 could tolerate the

observed inverter output voltage. However, it was weak in that it did not address

specific loads on the inverter and did not address the effect on the inverter itself

(Section 01.2).

The inspector identified boric acid crystals on a pipe-to-pipe suppo,c weld in the

Unit 3 letdown piping. The licensee determined that there was a 5/8-inch crack

beneath the boric acid crystals. The licensee's response to the inspector's

observations was timely and thorough, and included an inspection in which another

crack was identified (Section O2.1).

The licensee's Schedule 10 piping inspection initiative was good. However, the

justification for limiting the initial scope of the Schedule 10 piping inspections to the

charging pump suction piping was weak, in that it did not consider the potential for

the same types of problems in the equally-vulnerable letdown system piping

(Section 02.1).

Station Technical's evaluation of the plant response to a major grid disturbance was

timely and sufficiently detailed to assess plant response. This was an example of

good support by Engineering (Section E1.1).

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The licensee was proactive in initiating modifications to allow timely

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cross-connection of Units 2 and 3 emergency dirmal generators (EDGs) to improve

site safety (Section E2.1).

The licensee's proposed actions were acceptable '.1 response to the NRC's

determination that the shutdown cooling system valve power supplies were

undersized (Section E8.1).

The absence of a radiation monitor drain valve from any piping and instrumentation

drawing or procedure represented a lack of configuration control, which the licensee

recognized and corrected (Section R2.1).

4 Plant Sucoort

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Overall, plant chemistry sampling, in the one sample observed, was appropriately

performed. However, in one instance personnel attention to detail was observed to

be weak (Section R1.1).

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• The licensee's identification and corrective actions for a mispositioned radiation

monitor drain valve were prompt and appropriate. The bypass flow rendered an

important radiation monitor inoperable, but the significance of this condition was

mitigated by the availability of other secondary plant radiation monitors

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(Section R2.1).

Licensee performance in the Technical Support Center (TSC) during a quarterly

emergency preparedness (EP) drill was very good based on correctly recognizing

plant problems, taking appropriate actions, and identifying weakness during the

post-drill critique (Section P1.1).

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ReDort Oetails

Summary of Plant Status

Unit 2 operated at essentially 100 percent power throughout the inspection period, with

the exception of four short periods of operation at between 75 and 80 percent power to

support heat treating and cleaning the circulating water system. The periods of reduced

power operation were July 31-August 1, August 9-10, August 16-19, and August 24-25,

1996.

Unit 3 operated at essentially 100 percent power until August 2,1996, when power was

reduced to 1 percent, and the main generator was taken off line to support feedwater

heater repairs (see Section 01.1). Following the repairs, power was increased, and the

generator was synchronized to the grid. Power was maintained at essentially 100 percent

from August 5 until September 7, when power was again reduced for a heat treatment of

the circulating water system. At the end of this inspection period, power was at 94

percent and being increased to ' full power.

A significant grid disturbance occurred on August 10,1996, that did not significantly

disrupt operations at Units 2 or 3 (see Section E1.1).

l. Operations

01 Conduct of Operations

01.1 Unit 3 Downoower

l a. Insoection Scone (71707)

On August 2-3,1996, the inspector observed operators downpower and take the

j main generator off line to support feedwater heater maintenance. The inspector

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observed the power decrease from about 45 percent power to approximately 1

percent power.

b. Observations and Findinns

The control operator (CO) and assistant control operator (ACO) closely monitored

indications during the downpower. They communicated frequently and clearly with

, each other and with other Operations personnel, and frequently referred to

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applicable procedures, including alarm response procedures, as necessary.

The control room supervisor (CRS) remained in the control room and closely

monitored operator actions. The shift superintendent (SS) and the unit

superintendent also provided close oversight of the evolution.

In one instance, the CO and ACO diluted the RCS without first obtaining the

concurrence of the CRS. The dilution was needed to control axial shape index, and

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had been predicted by reactor engineering. The CO informed the CRS, who was

also in the "at the controls" area adjacent to the dilution controls, after the dilution

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had commenced, it was the licensee's practice for operators to obtain prior

concurrence from the CRS for reactivity manipulations. However, the CRS was in a

position to provide effective oversight. NRC regulations do not require senior

reactor operator concurrence of reactivity manipulations by other reactor licensed

operators. Although this was not a violation of NRC requirements, it was

considered an example of weak communications and command and control.

A feedwater control valve stuck partially open when reactor power was at

approx,imately 8 percent. Operators took prompt action to reduce power to

approximately 2 percent and to shift from main feedwater to auxiliary feedwater to

avoid tripping the reactor on high steam generator level. This unexpected transient

resulted in a power level change of greater than 15 percent within a one hour

period, which was not immediately recognized (see Section M8.1).

c. Conclusions

Command and control of the downpower, with the exception of the dilution, were

generally consistent with documented licensee management expectations and

procedures. Command and control of the dilution were adequate. Operator

attention to indications was good. The operators responded promptly and  ;

effectively to the transient resulting from the stuck feedwater control valve.  :

01.2 Class 1E Inverter 2YOO3 Outout Voltaae Indication

a. In_sp_pction Scope (37551. 71707. and 61726)

The inspector examined the Unit 2 Class 1E inverters and DC equipment rooms.

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b. Observations and Findinas

On August 5,1996, at approximately b:30 a.m., the inspector observed that the

output voltage of Inverter 2YOO3 indicated approximately 122.5 volts. A placard

next to the meter stated that the voltage should be between 118 and 122 volts.

The inspector confirmed that indicated output voltages of the other Unit 2 inverters

were within the posted ranges.

At approximately 6:10 a.m., the inspector informed the control room operators of

the condition, which the operators then con' firmed. The inspector observed that TS

.SR 3.8.7.1 requires the licensee to " verify correct inverter voltage," but that no

specific acceptable values are given in the TS or Licensee Controlled Specifications.

Operators informed the inspector that the SR had been deleted from Surveillance

Procedure SO23-3-3.27.2, " Weekly Electrical Bus Surveillance," Revision 5, which

contained a change summary that stated that the voltages are monitored weekly on

the Operator Rounds System. The Operator Rounds System Unit 2 Primary ACO

Round 23, item 37, provides minimum and maximum values for the inverter output

voltage of 118.0 volts and 122.0 volts, respectively. The inspector confirmed that

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this was a surveillance item,~ and'that the meter on the inverter panel was the

instrument used to determine the output voltage.

I The operators did not initially recognize the 118 122 volts range as the acceptance

criteria, but could find no other range in available documentation. The operators

3 checked system operating Procedure SO23-6-17, "'., lass 120 VAC Vital Bus Power

Supply System Operation," Revision 7, and determined that the only voltage range

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listed was also 118-122 volts. After discussions with the inspector, the operators

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determined that the range given in the Operator Rounds System, used to satisfy

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SR 3.8.7.1, appeared to be the acceptance criteria for the surveillance. The

j Operations and Station Technical Electrical managers stated that this range was not

determined by Engineering and did not necessarily. bound the operable range of the

i inverter. The Operations plant superintendent also stated that, in his opinion, the

0 weekly checks did not have to confirm operation within the design limits, and that

, the determination of " correct voltage" was intended to be more of a gross check for

proper function. He also stated that less frequent activities, such as refueling

j interval calibrations, were the methods used to ensure that the function was

consistent with the design.

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The operators contacted the STA, who rendered an immediate judgment that the l

inverter was operable, despite the output voltage being out of the normal range, l

!- based on his belief that the inverter could still perform its design function. He  !

contacted the cognizant engineer for the inverters at approximately 7:00 a.m., who l

also rendered the judgment that the inverter was operable, Based on this feedback, l

l the operators did not enter the actions for TS LCO 3.8.7.

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[ TS SR 3.0.1 states that " failure to meet a Surveillance, whether such failure is

experienced during the performance of the Surveillance or between performances of

the Surveillance, shall be failure to meet the LCO." Additionally, TS LCO 3.8.7,

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Action A.1, requires that with one required inverter inoperable, the AC vital bus -

i. must be powered from its Class 1E constant voltage source transformer within

j~ 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This action was not taken.

The Operations Manager stated that transferring the inverter loads to the alternate l

source would result in a less reliable and stable condition than leaving the loads on

l the inverter, if the inverter was operable. He stated that the SS was prepared to ,

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declare the inverter inoperable and take the required action if Station Technical had

! not judged that the inverter remained operable.

l The Updated Final Safety Analysis Report (UFSAR), Section 8.3.1.1.5.A, states that

, "the inverter power supplies are designed to regulate the steady-state voltage of

120 Vac within 2.0% at full power output for a load power factor of 0.8 at a

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frequency of 60 0.5 Hz." The licensee determined that these values were

identical to those in the procurernent specification for the inverter.

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The Station Technical Electrical manager informed the inspector that the meter on

the inverter panel had an accuracy specification of i3 volts (2 percent of full

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scale), and that the actual voltage could be within the required range even if that

indication was not within the range.

The inspector reviewed the last calibration of the inverter and the meter, per j

Maintenance Order 92101753, performed in June 1993, and determined that it I

allowed a i3.0-volt tolerance for the installed voltmeter, using a meter with a l

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iO.6-volt accuracy at 120 volts. The actual inverter output voltage was calibrated

to 120 i2.0 volts, also using a voltmeter with a 10.6-volt accuracy at 120 volts.

. This resulted in a procedurally-allowed inverter output voltage ranging from 117.4 i

to 122.6 volts, slightly outside the design range of 117.6 to 122.4 volts. However, j

the licensee's practice was to leave the inverters set to the middle of the range. For l

Inverter 2YOO3, the output voltage was left at 119.4 volts, which with instrument  !

inaccuracy resulted in an actual output of 118.8 to 120.0 volts, which was within

the design range. I

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At approximately 12:15 a.m. on August 5, test technicians completed taking

voltage readings from inside the cabinet using a voltmeter with an accuracy of

11.1 volts. The licensee confirmed that the output voltages of Class 1E inverters

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in Units 2 and 3 were within the normal range, and also adjusted the calibration of

the voltmeters on the inverter panels.

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At 1:30 p.m., Station Technical completed documentation of an operability

assessment in AR 960801065. The operability assessment determined that the

inverter was operable because " equipment designed to operate on 120 volts -

nominal is typically designed to operate with a variation of 10 percent." The

operability assessment also considered a National Electric Code requirement for ,

branch circuits to be designed for no more than a 3 percent voltage drop. The  !

inspector observed that the operability assessment did not address the specific

loads the inverter supplied nor the effect on the inverter when operating outside of i

its design range. 1

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At approximately 4:30 p.m. on August 5, the licensee completed a Procedure I

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Modification Permit for Surveillance Procedure SO23-3-3.27.2 to restore the inverter

voltage check surveillance to the procedure, and to change the acceptance criteria

to 12011.3 volts, using a Fluke with an accuracy of 1.1 volts. The inspector

observed that this revised acceptance criteria was acceptable to demonstrate that

the inverter output was within the design specification of the inverter.

In response to this finding, the licensee began an effort to identify surveillances that

lacked appropriate specific quantitative or qualitative acceptance criteria, and to

verify that bases existed for the acceptance criteria. l

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c. Conclusions l

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The licensee failed to declare inverter 2Y003 inoperable and to take the actions

specified by TS LCO 3.8.7, as required by TS SR 3.0.1, after the output voltage

was identified as being outside the acceptance criteria for TS SR 3.8.7.1

(documented in the Operator Rounds System). This is a violation of TS SR 3.0.1

(Violation 50-361/96009-01).

Operations management focused on nuclear safety in not wanting to transfer the

inverter loads to the alternate source, which was less reliable, as long as the

inverter was operable. Management considered the inverter operable based on the

judgment of the STA and cognizant engineer.

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The licensee determined that the Operator Rounds System, used to accomplish the

weekly surveillance test, was not appropriate for the circumstances, in that the

acceptance criteria were not clearly understood as being acceptance criteria, and

the instrument used, in conjunction with the acceptance criteria, did not have the

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required accuracy to confirm that the vo!! age was witain the design range. This

was a violation of 10 CFR Part 50, Appendix B, Criterion V, which states that

" activities affecting quality shall be prescribed by documented instructions,

procedures, or drawings, of a type appropriate to the circumstances and shall be

accomplished in accordance with these instruction, procedures, or drawings.

Instructions, procedures, or drawings shallinclude appropriate quantitative or

qualitative acceptance criteria for determining that important activities have been

satisfactorily accomplished." This licensee-identified and corrected violation is

being treated as a noncited violation, consistent with Section Vll.B.1 of the NRC

Enforcement Poliev (NCV 50-361(362)/96009-02).

The operability assessment documented in AR 960801065 provided some

assurance that the loads could tolerate the observed inverter output voltage.

However, it was weak in that it did not address specific loads on the inverter and

did not addiess the effect on the inverter itself.

02 Operational Status of Facilities and Equipment

O2.1 Letdown Pressure Control Valves in Unit 3

a. insoection Scope (71707 and 71750)

The inspector performed a routine inspection of safety-related and

important-to-safety equipment in the radiologically controlled area.

b. Observations and Findinas

The inspector observed that letdown pressure regulator Valve 3PV201 A was

continually cycling and was very noisy. Although the inspector had previously {

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observed that this valve continually cycled, on this occasion s.ome piping vibration

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was also detected. The licensee stated that they were working on circuit design

changes to minimize the valve cycling.

The licensee's letdown design has two parallel pressure regulator valves. During

inspection of pressure regulator Valve 3PV201B, the inspector noted a buildup of

boric acid crystals on a pipe-to-pipe support weld, downstream of the valve. The

inspector did not observe any moisture in the weld area. The inspector notified the

licensee. The licensee cleaned away the crystals and observed an approximate

5/8-inch crack in the weld. The licensee stated that the pipe was stainless

Schedule 10 and was not within their ASME Code program, but that a similar crack

had been experienced in a charging syshon line (see NRC Inspection Report

50-361/95-13, 50-362/95-13).

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The licensee determined that the leak was not active. The licensee analyzed the

boron crystals and determined that they had accumulated over a 4 month period.

The inspector observed that a drop would slowly occur at the crack location (less

than one drop per day). The licensee performed an operability determination and

considered that the system remained operable. The inspector reviewed the

operability determination and considered it adequate. The licensee intended to

monitor the crack and shut down to repair the weld if a leak of a predetermined rate

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occurred.

The inspector questioned why the boric acid crystals were not found by licensee

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system engineering and operations tours. The Operations ;ranager stated that

operators usually focused more attention on components that were prone to

leakage. He stated that this example would be used to heighten awareness that

operators should be more observant of piping conditions.

The inspector questioned the licensee regarding current maintenance program for

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this piping. Licensee engineering personnel stated that a plan for identification and

inspection of Schedule 10 piping, on the suction side of the charging pumps, had

been initiated following a crack previously identified in that piping (see NRC

Inspection Report 50-361/95-13,50-362/95 13). As the letdown crack was

outside of that scope, the licensee intended to reassess the inspection scope as

appropriate. The schedule and scope of piping inspections had not been revised by

the end of this inspection period. The original scope was limited to safety-related

piping. The letdown system is not safety-related, but is operationally important and

classified as important to safety.

A similar crack was identified on another welded support on same letdown pipe, but

in an infrequently accessed high radiation area /high contamination area, during a

followup inspection by the licensee, accompanied by the inspector, on September 5,

1996.

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c. Conclusions

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The licensee's response to the inspector's observations was timely and thorough.

A weakness in the performance of operator rounds was identified as the result of

operators not identifying the 4-month old boric acid buildup in an easily accessible,

welllighted area.

The licensee's Schedule 10 piping inspection initiati.e was good. However, the

justification for limiting the initial scope of the Schedule 10 piping inspections to the

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charging pump suction piping was weak, in that it did not consider the potential for

similar types of problems in the equally-vulnerable letdown system piping.

05 Operator Training and Qualification

05.1 Simulator Trainino

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a. inspection Scoce (41500)

The inspector observed an evaluated simulator scenario. The scenario, which was

conducted as planned, involved loss of a circulating water pump, a rapid

downpower, and a steam generator tube rupture with concurrent loss of all

feedwater.

b. Observations and Findinas

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i Operators appeared to satisfactorily perform all expected actions and behaviors.

Communications were clear, and the command and control function was

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well-executed. Abnormal operating procedures and emergency procedures were

followed.

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Conclusions

The simulator scenario sufficiently exercised operator skills to allow effective

evaluation of their performance. Operators performed as expected, with no

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08 Miscellaneous Operations issues (92901)

08.1 (Closed) Violation 50-361(3621/96002-01: failure to comply with TS administrative

requirements for procedure reviews. The initial violation consisted of two examples,

one for failure to perform TS division management review of certain temporary

change notices (TCNs) prior to implementation and the second for failure to perform

TS division management review of certain abnormal alignments, which were

considered by the NRC as being test evolutions, prior to implementation.

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i The licensee did not believe that either example constituted a violation, as noted in

, its letter to the NRC dated May 20,1996. By letter dated July 19,1996, the NRC

withdrew the first example concerning review of TCNs and retained the second

example concerning the abnormal alignments.

a. Inspection Scone

The inspector reviewed the Notice of Violation, licensee and NRC letters, and ,

licensee corrective actions and enhancements.  !

b. Observations and Findinas

Although the first example of the Notice of Violation was withdrawn, the licensee's

review of the administration of its TCNs indicated areas where enhancements could

be made. The licensee listed these enhancements in their May 20,1996, letter.

The inspector reviewed the enhancements and considered that they were proactive

in improving the administration of TCNs.

Licensee representatives stated that they planned to accept the NRC conclusion that

the second example constituted an evolution, which would have required prior

division management approval. The licensee changed the program to include

division management approval of abnormal alignments which perform test

evolutions. The inspector confirmed that the program had been changed.

The inspector reviewed the abnormal alignments cited in the second example with

the licensee, including the safety evaluation contained in Abnormal Alignment

2-95-138, concerning operation of a high pressure safety injection (HPSI) pump to

test check valves. The licensee noted that the safety evaluation had specifically

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evaluated pump flow requirements and took steps (by opening the bypass flow

valves) to ensure that the pump vendor operating limits were not exceeded.

Because the procedure required that the by-pass flow valve be open, the licensee

considered that there was no safety significance with the examples cited, from the

standpoint of the potential to damage the HPSI pump. The inspector acknowledged

that the licensee procedure operated the HPSI pump within its operating limits.

The licensee also discussed the development of the cited abnormal alignments and

how the licensee had evaluated the potential for over-pressurization of the low

pressure safety injection piping. The licensee ackncwledged the observation, in

Inspection Report 50-361(362)/95-07, that tr.a pctential for over-pressurization

existed. The inspector noted that the licensee understood the safety significance of

the over-pressurization potential and had incorporated the over-pressurization

mitigation strategy into the applicable procedure.

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11. Maintenance

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M1 Conduct of Maintenance

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j M 1.1 General Comments

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a, inspection Scoce (62703)

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The inspector observed all or portions of the following work activities:

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• 96080723000 replace Unit 2 plant vent stack wide range gas Monitor  !

l 2RY7865-1 grab sample timer -

i * 96080242000 clean and inspect component cooling water Heat

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• 94080807000 monitor current at HPSI Pump 3P017 breaker  :

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The inspectors found the work performed under these activities to be thorough and l

l proper. All work observed was performed with the work package present and in

active use. Technicians were knowledgeable and demonstrated the skills necessary

. for the work. When applicable, appropriate radiation controls were in place.

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M1.2 Generai Comments on Surveillance Activities <

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j a. inspection Scone (61726)

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The inspector observed all or portions of the following surveillance activity:

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• Monthly Fuel Handling Building Post-Accident Air Cleanup System

1 Test"(Unit 2)

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b. Observations and Findinas

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i The inspectors found the surveillance performed under this activity to be thorough.

The surveillance was performed with thc procedure present and in active use. The

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technicians were knowledgeable and demonstrated the skills necessary for the

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work.

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In addition, see the specific discussion of a surveillance observed under  !

Section M3.1 below.

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M2 Maintenance and Material Condition of Facilities and Equipment l

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M2.1 General Plant Conditions

j a. Insoection Scope (71707 and 71750)

l The inspectors performed walkdowns in most accessible plant areas.

b. Observations and Findinas

j The inspectors observed approximately 20 indications of minor boric acid leaks and

- similar deficiencies that were not identified with deficiency tags. The licensee did

i

not require deficiency tags to be hung, and approximately half of the deficiencies

I

were already in the licensee's corrective action system. The licensee entered the

!

others into the corrective action system. The number of deficiencies was about

4

twice the number identified by NRC personnel in recent months. None of the

identified deficiencies appeared to impact equipment operability.

The licensee monitored the numbers of drip bags on a weekly bases. As of

August 29,1996, only 14 drip bags were installed in Units 2 and 3.

I c. Conclusions

! Minor deficiencies were generally being identified by the licensee, although some

were not. The increase in the number of inspector-identified deficiencies indicates a

! slight negative trend in material condition. However, the overall material condition,

j with respect to boric acid leaks, was very good and was being well managed.

,

i M3 Maintenance Procedures and Documentation

i

M3.1 Maintenance Rule Status Reoort Review

a. Insoection Scoce (62707)

.

The inspector reviewed a July 1996 Monthly Maintenance Rule status report, issued

by a licensee memorandum dated August 19,1996; 10 CFR 50.65, " Requirements

for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," (the

] Maintenance Rule); NUMARC 93-01, May 1993, " Industry Guideline for Monitoring

j the Effectiveness of Maintenance at Nuclear Power Plants;" NRC Regulatory Guide

1.160, " Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

which endorsed the NUMARC guidance; and NRC Inspection Report 50 528/9609

j containing the results of a Maintenance Rule implementation inspection conducted

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at Palo Verde Nuclear Generating Station. The inspector met with licensee

personnel on September 6,1996.

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b. Observations and Findinas I

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Section (a)(2) of the Maintenance Rule requires a normal level of monitoring of

structures, systems, or components (SSCs) "where it has been demonstrated that

the performance or condition of the SSC is being effectively controlled through the ,

performance of appropriate preventive maintenance, such that the SSC remains l

capable of performing its intended function." I

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Section (a)(1) of the Maintenance Rule requires licensees to " monitor the

performance of SSCs against licensee-established goals, in a manner sufficient to ,

provide reasonable assurance that such SSCs . . . are capable of fulfilling their

intended functions. Such goals shall be established commensurate with safety and,

where practical, take into account industry-wide operating experience. When the

performance or condition of a SSC does not meet established goals, appropriate

corrective action shall be taken."

The inspector observed that the licensee status report indicated that 15 SSCs had

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exceeded performance criteria as monitored per Section (a)(2) of the Maintenance

Rule. The licensee determined that these SSCs exceeded the criteria, based on

either availability or functional failures or repetitive failures during the last four

calendar quarters prior to July 10,1996-- the date of required implementation of

4

the Maintenance Rule. The licensee had generated ARs to Station Technical

personnel to evaluate goals for these SSCs. The inspector requested that the

licensee provide the goals for these SSCs per Section (a)(1) of the Maintenance

Rule. As of September 6,1996, the licensee stated that they had not completed

goal-setting evaluations for the 15 SSCs. The licensee informed the inspector that

the goals for each of these SSCs were the same as the performance criteria being

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used per Section (a)(2) of the Maintenance Rule. The ARs generated were meant to

enhance this generic goal. For example, the goal for an SSC would be no more

functional failures, until the SSC met the performance criteria of no more than three

functional failures for a defined time period, given that the SSC had already

!

experienced the three functional failures.

The licensee did not have procedural guidance for the timeliness of the goal-setting

evaluations. The Station Technical manager stated that his expectation was that

the goal setting would be completed within 30 days from the time the determination

was made that a component or system was in (a)(1), but that the first round of goal

setting would take longer to ensure that it was properly accomplished. The licensee

recognized the vulnerability to criticism if additional functional failures occurred

before goals were set and enhanced monitoring implemented.

The inspector observed the following concerning requirements for goals under

Section (a)(1) of the Maintenance Rule (with the basis in parenthesis):

A cause determination is required when a SSC does not meet performance

criteria. Goals may be at the system, train, component, or structure level,

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depending on the cause determination. Monitoring of SSC performance

against these goals should be based on the availability of plant specific or

industry data, and should allow for early detection of negative trends

(NUMARC guidance).

• If performance criteria are not met, the basis for the criteria should be

reviewed to determine if goal setting is required and the appropriate goal

value established. It should be recognized that while goals and performance

writeria may have the same value and units, goals are only established under

(a)(1) where performance criteria are not being met and are meant to provide

reasonable assurance that the SSCs are proceeding to acceptable

performance (NUMARC guidance).

• Cause determination results and performance against the Section (a)(1) goals

should be documented (NUMARC guidance).

Based on the above, the inspector found that for each SSC the licensee identified as

not meeting performance criteria per Section (a)(2), the licensee was required to

develop a cause determination and set goals under Section (a)(1), based on that

cause as outlined above. In some instances it may have been appropriate to use

the performance criteria as the goal.

This issue was unresolved at the end of this inspection period. To resolve this issue

the inspector will evaluate each of the SSCs that the licensee identified as not

meeting performance criteria for the appropriateness and timeliness of the licensee's

actions, given that the Maintenance Rule was to be fully implemented on July 10,

1996 (Unresolved item 50-361(362)/96009-03).

M3.2 Erroneous Surveillance Data Not Noted by Licensee Personnel

a. Insoection Scope (61726)

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On August 30,1996, the inspector reviewed completed Instrumentation Procedure

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SO23-II-5.8, Revision 12, "SR N.I. Safety Channel D Drawer Test Linear Power

Subchannel Gains Functional Test and Channel Calibration." This TS required

surveillance had been completed by l&C technicians on Unit 3 Safety Channel D on

August 27,1996. On September 5,1996, the inspector interviewed the two l&C

technicians who performed the surveillance,

b. Observations and Findinns

The inspector observed that Step 6.6.4 of the surveillance procedure, to record the

output power meter reading of the linear power amplifier when a test switch was

positioned to insert a test signal to the input of the amplifier, was recorded as an

actual meter reading outside of acceptance criteria listed in the same step. The

acceptance band for the meter was 5.0 E-4 to 1.2 E-3 percent power, and the

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l actual meter reading recorded was 8.0E-6 percent power. The inspector informed

e l&C supervision and the shift supervisor, and observed that this out-of-specification

j parameter had not been previously reconciled by licensee personnel. After the

surveillance was completed on August 27,1996, the l&C technicians reported to

the control room operators that the instrument, in regards to gain on the amplifier,

l was satisfactory. l&C supervision had not yet reviewed the complete surveillance l

procedure as of August 30,1996, although two reviews were indicated as required  !

by signature block. Programmatically, there was no time requirement for l

completion of these reviews when the surveillance was being performed to fulfill the  !

j normal SR. The technicians performing the surveillance would review the

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completed surveillance themselves and then inform the control room operators of

any unsatisf actory parameters.

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In response to the inspector's observation, the shift supervisor declared the channel

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inoperable because of unsatisfactory performance of this surveillance. The channel

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had previously been declared inoperable for unrelated reasons (an excessive number

of spurious trips). On August 30,1996, the licensee performed this portion of the j

surveillance again, and recorded a satisfactory meter reading. Based on this and the  !

interviews of the technicians involved, the inspector found that the meter reading

had actually been satisfactory on August 27,1996, that the technicians had not

, recorded the actual meter reading properly, and had failed to note this prior to

. informing the control room operators that the amplifier gains were satisfactory.

c. Conclusions

l

The inspector found that this situation had no safety consequence since the gain

was actually satisfactory and the technician had observed the meter to be reading

within acceptance criteria but had mistakenly recorded the in-specification

i parameter as out-of-specification. The l&C technicians, in this instance,

j demonstrated inattention to detail by recording a meter reading erroneously.

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j M8 Miscellaneous Maintenance issues (90712)

1

l M8.1 (Closed) Licensee Event Report (LER) 50-362/96003-00: delinquent iodine sample

3

analysis following 15 percent power change in one hour period. At

approximately 4 p.m. on August 3,1996, during a review of data from a

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planned downpower of Unit 3 (see Section 01.1), the licensee determined

that an SR had been missed because operators had failed to recognize that

j power had been decreased by greater than 15 percent in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. SR 4.4.7

l (Table 4.4-4) requires than the RCS be sampled and analyzed for iodine

<

between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a change of power in excess of 15 percent

in a 1-hour period. The licensee determined that power had been decreased

by approximately 16 percent between 3

15 a.m. and 4:15 a.m. on August 3,

1996.

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A routine chemistry sample had been taken at 8:30 a.m., but had not been analyzed

promptly for iodine. The licensee analyzed this sample, and obtained and analyzed

another sample, with no unexpected results. During the downpower, which the

inspector had observed, an unexpected transient occurred that resulted in power

being quickly reduced by about 6 percent. The operators were paying close

attention to their indications and were logging power level every 30 minutes as

required by procedures. However, this manual log did not reveal that power had

changed by more than 15 percent in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, which was evident from the

subsequent review of power level graphs. Additionally, due to the level of activity

following the transient, the SS did not immediately request a review of the power

history to confirm compliance with the TS. The licensee initiated AR 960800223

and a Level 2 event report to investigate the event and to document additional

corrective actions. This licensee-identified and corrected violation is being treated

as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement

Policy (NCV 50-362/96009-04).

Ill. Enaineering

E1 Conduct of Engineering

E1.1 _ Grid Disturbance (37551)

, Plant response to the major grid disturbance on August 10,1996, was as designed.

Two steam bypass control valves opened briefly, and the core operating limits

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supervisory systems stopped automatic calculations, as a result of the transient.

The initial voltage sag was approximately 10 percent, resulting in degraded voltage

i flags on the Class 1E 480 volt buses. Station Technical completed an evaluation of

l the plant response on August 14, confirming that the plant response was as

l designed.

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Conclusions

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l The inspector concluded that Station Technical's evaluation of the plant response

! was timely and sufficiently detailed to assess plant response. This was an example

l of good support by engineering.

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l E2 Engineering Support of Facilities and Equipment

E2.1 On-site Emeroency Power (37551)

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l One of the items simulated during the quarterly EP drill on August 7,1996, was I

loss of offsite power and failure of EDGs in Unit 2 to start. Both EDGs in Unit 3

were simulated to start. Simulated Unit 2 plant conditions deteriorated due to lack

of electrical power.

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Currently, interlocks exist which prevent any timely connection of EDGs in one unit

to the other unit. During past inspections, the inspector had discussed with

licensee engineering and probabilistic risk assessment personnel whether being able

to cross-connect EDGs between units provided a safety benefit. The licensee

studied the benefits of having EDGs available to support the opposite unit and had

recently concluded that the improvement in safety warranted making the necessary

hardware and procedure modifications. The licensee noted that the associated

design change was in the review process.

.

Conclusions

The inspector considered that the licensee was proactive in initiating modifications

to allow timely cross-connection of Units 2 and 3 EDGs to improve site safety.

E2.2 Review of Facility and Eauioment Conformance to UFSAR Descriotion (37551)

A recent discovery of a licensee operating its facility in a manner contrary to the

UFSAR description highlighted the need for a special focused review that compares

plant practices, procedures and/or parameters to the UFSAR descriptions. While

performing the inspections discussed in this report, the inspectors reviewed the

applicable sections of the UFSAR that related to the inspection areas inspected.

The inspectors verified that the UFSAR wording was consistent with the observed

plant practices, procedures and/or parameters.

E8 Miscellaneous Engineering issues (92903)

E8.1 (Closed) Unresolved item 50-361(362)/95201-01: adequacy of shutdown cooling

valve power. Due to equipment substitutions made during construction, which

rendered the electrical supply equipment undersized, the licensee found that fuses

which supplied power to these valves occasionally blew during initial valve stroking.

The licensee's corrective action was to install two pre-wired spare fuses and a

selector switch for each circuit. In NRC Inspection Report 50-361(362)/95-201, the

NRC noted that the modification required operator action to locally select the spare

fuses and considered that the modification may have increased the likelihood of

equipment failure when compared to the original design.

In a letter dated July 12,1996, the NRC informed the licensee that the design did

not comply with industry guidance, but that the design did provide an acceptable

level of safety until a permanent solution could be implemented.

in a letter dated August 26,1996, the licensee committed to make a permanent

3 design change during each unit's Cycle 10 refueling outage.

The inspector reviewed the circuit design, fuse failure records, and associated NRC

and licensee letters. The inspector noted that the licensee's August 26,1996,

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letter provided several options for a permanent change, which appeared to address

correction of the problem.

Conclusions

The NRC determined that the existing design provided an acceptable level of safety,

and that the licensee's actions did not constitute a violation of NRC requirements.

, IV. Plant Sucoort

R1 Radiological Protection and Chemistry Controls

. R1.1 Samolina and Chemistry

a. Insoection Scope (71750)

The inspector performed a review of secondary water activity analysis and radiation

monitor alarm status, a review of selected plant chemistry results against TS and

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procedural limits, and observed portions of reactor coolant and ov'/ gen samples

taken from Units 2 and 3.

b. Observations and Findinas

The inspector verified that secondary water activity analysis results were below

action levels and that radiation monitors did not indicate degradation of steam

generator tube integrity. The inspector also reviewed sample results for RCS total

activity and dose equivalent iodine, which were below licensee procedural and TS

limits. The inspector observed RCS sampling performed by chemistry personnel and

considered that, overall, the activities were conducted in accordance with

procedural controls. However, while obtaining a Unit 2 RCS sample, the chemistry

technician appeared to bypass two steps in Sampling Procedure SO23-ill-16-23,

. Revision 12, " Units 2/3 - Normal Operation of the Reactor Coolant Sample System,"

as he turned to another page. When the inspector questioned the technician

j regarding the steps, the technician acknowledged the validity of the inspector's

observation and subsequently performed the steps. However, had the omission

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occurred, the result would have been negligible as the steps were only necessary to

depressurize the sampling lines to a sample vessel prior to the sample vessel's

removal from the sample sink.

Sampling results were reviewed and found to be below any action levels,

c. Conclusions

Overall, plant chemistry sampling was appropriately performed. However, in one

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instance personnel attention to detail was observed to be weak.

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R2 Status of Radiological Protection and Chemistry Facilities and Equipment

R 2.1 Steam GeD#Leor Blowdown Radiation Monitor '/give Alianment (Unit 3.1

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a. Inspection Scope (71750)

The licensee identified and reported, in AR 960800600, that an undocumented

valve was found open, which effectively bypassed the sample flow for Steam

Generator 3E088 Blowdown Radiation Monitor 3RE6759. The valve was not

identified on any piping and instrumentation drawing or in any procedure. The

inspector reviewed the AR and discussed the issue with cognizant licensee

personne!. The inspector also reviewed the licensee's emergency operating

procedures.

b. Observations and Findinas

The licensee determined that the condition rendered the radiation monitor

inoperable, but that the condition was not reportable. The flow switch for the

i sample flow was upstream of the opened valve, so the bypass flow was not able to

be detected by the flow switch. The basis for this was that the monitor is not

required by the TS, and that other means existed for monitoring radioactivity in the

, secondary side of the steam generators. The inspector determined that this was

accurate.

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The licensee was unable to determine when or how the valve was mispositioned.

The licensee promptly checked the drain valves on other secondary plant radiation

monitors and determined that they were properly positioned.

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The licensee determined that the valves were not needed and initiated action to

remove the valves.

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The inspector reviewed the licensee's Emergency Operating Instructions

l SO23-12-1, " Standard Post Trip Actions," Revision 12, and SO23-12-4, " Steam

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Generator Tube Rupture," Revision 13, and determined that this blowdown radiation

monitor was one of six monitors used to detect radiation levels and trends in the

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secondary plant. The inspector observed that because of the lag time in this

monitor, it would generally be the secondary or tertiary indication of secondary

plant radioactivity. The inspector also observed that the steam generator blowdown

radiation monitors (one per generator) were the only secondary plant radiation

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monitors that would be available after a main steam isolation actuation. Additional

review to detemine the potential importance of the steam generator blowdown

radiation monitor on event diagnosis will be conducted (Followup

item 50-362/96009-05).

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c. Conclusions

The licensee's identification and corrective actions for the mispositioned radiation

monitor drain valve were prompt and appropriate. The bypass flow rendered an

important radiation monitor inoperable, but the significance of this condition was

mitigated by the availability of other secondary plant radiation monitors. However,

this could have negatively impacted the accuracy and timeliness of event diagnosis.

The absence of the drain valve from any piping and instrumentation drawing or

procedure represented a lack of configuration control, which the licensee recognized

and corrected. -

This issue will be further reviewed as a followup item to address the potential

significance of the inoperability of this monitor and the affect on event prognosis.

P1 Conduct of EP Activities

P1.1 Quarterly EP Drill

a. Inspection Scone

The inspector witnessed the activities within the TSC during the quarterly EP drill on

August 7,1996. The drillincluded loss of the Emergency Operations Facility and I

management of activities from the TSC.

b. Observations and Findinas

The inspec, tor observed that the licensee staff correctly recognized the scope of

each problem and followed their emergency procedures to address these problems.

Emergency Action Levels were correctly determined. The licensee's Station

Emergency Director maintained overall control of the TSC, focused only on major l

issues, and provided clear directions to support staff. However, the inspector  !

observed a few deficiencies, including radio transmissions that were not received,

poor communications related to deterrnining inside containment radiation readings,

and the failure of some personnel to listen to the periodic briefings. After the drill

licensee management personnel independently identified these weaknesses and

assigned corrective actions. Two aspects of the drill are discussed in Sections E2.1

and P1.2. j

c. Conclusions

Licensee performance in the TSC was very good based on correctly recognizing ,

plant problems, taking appropriate actions and identifying deficiencies during the

post-drill critique.

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P1.2 Containment Radiation Monitors

The licensee had determined that the in-containment radiation monitors in both units

were inoperable due to susceptibility of cable connectors to moisture intrusion. As

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discussed in LER 50-361(362)/96-005, the licensee had established an alternate

means of determining in-containment radiation readings as required by the new

standard TS 3.3.3.1. The alternate means consistad of taking outside-containment

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radiation readings and estimating the in-containment readings using pre-prepared

4 charts.

During the EP drill on August 7,1996, outside-containment radiation readings were

taken, and assigned personnel located and utilized the charts to determine in-

containment radiation readings and to assess core damage. However, the managers

and other key personnel in the TSC did not know that the charts had been located

and were being used, so the Station Emergency Director was never provided with

any estimates of in-containment radiation readings. At the post-drill critique,

licensee personnel stated that the charts were available and that they would ensure

that cognizant TSC personnel had access to the charts.

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The inspector briefly reviewed the charts and noted that they did not consider the

effects of containment spray. On August 14,1996, the licensee issued a

Memorandum for File, " Core Damage Estimation Based on Dose Rate at

Containment Outside Surface." The inspector will review the technical adequacy of

this memorandum as part of the followup of LER 50-361(362)/96-005.

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management

at the exit meeting on September 10,1996. The licensee acknowledged the

findings presented.

At the exit meeting, the licensee informed the inspectors that a more rigorous

operability assessment for the Class 1E inverter (Section 01.2) had been completed,

concluding that Inverter 2YOO3 was operable (able to perform its design function)

with an output voltage of 122.5 volts. The assessment did not support the inverter

being operable for the 120 volts i10 percent, discussed in the original operability

determination.

The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary. No proprietary information was

identified.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

D. Brieg, Manager, Station Technical

J. Clark, Manager, Chemistry

J. Fee, Manager, Maintenance

G. Gibson, Manager, Compliance

R, Krieger, Vice President, Nuclear Generation

D. Nunn, Vice President, Engineering and Technical Services

T. Vogt, Plant Superintendent, Units 2 and 3

R. Waldo, Manager, Operations

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INSPECTION PROCEDURES USED

"

!P 37551: Onsite Engineering

IP 41500: Training and Qualification Effectiveness

IP 61726: Surveillance Observations

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 90712: In-Office LER Review

IP 92901:

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Followup - Operations

IP 92903: Followup - Engineering

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ITEMS OPENED AND CLOSED

Opened

50 361/96009 01 VIO failure to declare component inoperable when SR was not

satisfied (Section 01.2)

50-361/96009-03 URI maintenance rule implementation - goal setting

50-362/96000-03 (Section M3.1)

50 362/06009-05 IFl importance of the steam generator blowdown radiation monitor

on event analysis (Section R2.1)

Onened and Closed

50-361/96009-02 NCV inadequate surveillance procedure (Section 01.2)

50-362/96009-02

50-362/96009-04 NCV delinquent surveillance for RCS iodine sample following power l

change greater than 15 percent (Section M8.1) I

Closed

50-361/95201-01 URI adequacy of shutdown cooling valve power (Section E8.1)

50 362/95201-01

50-361/96002-01 VIO failure to comply with TS administrative requirements for

50-362/96002-01 procedure reviews (Section 08.1)

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50-362/96003-00 LER delinquent iodine sample analysis following 15 percent power

change in one hour period (Section M8.1)

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LIST OF ACRONYMS USED

ACO assistant control operator

AR action request

CO control operator

CRS control room supervisor

EDG emergency diesel generator

EP emergency preparedness

HPSI .high pressure safety injection

l&C instrumentation and control

LCO limiting condition for operation

LER licensee event report

, MO maintenance order

POR Public Document Room

RCS reactor coolant system

SR surveillance requirement

SS shift superintendent

SSC structure, system, or component

STA shift technical advisor

TCN temporary change notice

TS Technical Specification

TSC technical support center *

UFSAR Updated Final Safety Analysis Report *

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