ML20127A679

Insp Rept 50-483/92-15 on Stated Dates.Violations Noted. Major Areas Inspected:Plant Events,Operations & Maint/ Surveillance Conducted

ML20127A679
Person / Time
Site:	Callaway
Issue date:	12/31/1992
From:	Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20127A665	List: ML20127A662 ML20127A670 ML20127A679
References
50-483-92-15, NUDOCS 9301120038
Download: ML20127A679 (17)

See also: IR 05000483/1992015

Text

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. V. S. NUCLEAR REGULATORY COMMISSION

REGION 111

Report No. 50-483/92015(DRP)

Docket No. 50-483 License No. NPF-30

Licensee: Union Electric Company

Post Office Box 149 - Mail Code 400 '

St. Louis, MO 63166 i

Facility Name: Callaway Plant, Unit 1

Inspection at: Callaway Site, Steedman, MO '

Inspection Conducted: October 1 through December 18, 1992

Inspectors: B. L. Bartlett

D. R. Calhoun

Approved By: .

/ /,2 @ -fz l

T;7RT~ ac , Chief Date

Reactor jects Section 3A

e

inspection Summary

Inspection from October 1 through December 18.'1992 (Report No. 50-

483/92015(DRP))

Areas Inspected: Routine unannounced safety it. pections of plant events, a

operations, and_ maintenance / surveillance was conducted.

Results: Of the areas inspected two violations were identified. One

-violation involved the failure to properly set the_close limit = switch on a

safety-related valve (paragraph. 2.a.) and one violation involved the failure

to ' lock a valve (paragraph 3.a.). A summary follows.

Operations

On October 17,_ all control room annunciators were lost which,-according to-

their emergency action level procedures, required the licensee to declare an

Alert; however, _the licensee failed to' do- so. This event was the subject of

an NRC augmented inspection team and a special. inspection' See NRC Inspection

.

Reports 50-483/92018 and 50-483/92020 for additional details.

During a routine tour of the plant, the licensee found that a valve in.the

chemical and volume control system was not properly locked by its locking

device. The valve was in its required closed position. Upon notification,-the

licensee locked the valve. The failure to lock the valve was cited as a

violation.

9301120038 921231

PDR- ADOCK 05000483-

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- Radiological -Control s

During this report period no significant health physics findings were .

-identi fied.

Maintenance / Surveillance

On October 30, the licensee discovered that an essential service water valve's

close limit switch had been improperly set during maintenance activities in

the last refueling outage. Instead of going fully closed, the valve could

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-only go about 75 percent closed. Subsequent detailed analysis by the-licensee '

identified that the valve's failure to fully close did not prevent the safety-

related system from performing its intended -function.ihe failure to properly

set the close limit switch is considered an apparent violation and is being

evaluated for escalated enforcement.

' Engineerina and Technical Support

Engineering-exhibited good: plant support in the safety analysis of the

mispositioned essential service water valve. In addition, good initiative and

follow-up were noted on the identification of this issue by engineering. Good

engineering support was noted in the follow-up into the vital inverter =

problems experienced by the licensee during this report period.

Safety Assessment and Quality Verification

Good root cause analysis, corrective action identification and follow-up were

noted on the various issues identified during this report period. Strong,

aggressive, and detailed management attention was exhibited in the

identification and follow-up to all issues discussed in this inspection

report.

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DETAILS

1. Persons Contacted

D. F. Schnell,-Senior Vice'. President, Nuclear

1 *G. L. Randolph, Vice President, Nuclear Operations

• W. R. - Campbell, Manager, Callaway Plant

• C. D. Naslund, Manager, Nuclear Engineering

• J. V. Laux, Manager, Quality Assurance

• J. R. Peevy, Manager, Operations Support

• M. E. Taylor, Assistant Manager, Work Control

• D. E. Young, Superintendent, Operations

R. R. Roselius, Superintendent, Health Physics

T. P. Sampson, Supervising Engineer, Site Licensing ,

G. J. Czeschin, Superintendent, Planning and Scheduling

G. R. Pendegraff, Superintendent, Security

• C. E. Slizewski, Supervisor, Quality Assurance Program

G. A. Hughes, Supervisor, Independent Safety Engineer Group

• C. S. Petzel, Quality Assurance Engineer

• J. A. McGraw, Superintendent, System Engineering

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• R. D. Affolter, Superintendent, Design Control

• M. A. Reidmeyer, Engineer, QA

• J. D. Blosser, Manager At Large

• J. F. Hogg, Superintendent, Maintenance

• M. R. Lane, Supervising Engineer, Maintenance

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• R. H. Batey, General Supervisor *

• Denotes those present at one or more exit interviews.

In addition, a number of equipment operators, reactor operators, senior.

reactor _ operators, and other members of the quality control, operations,.

maintenance, health physics, and engineering staffs were contacted.

2. Onsite Follow Up-of Events (93702)

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a. Mispositioned Essential ~ Service Water to Ultimate Heat Sink:

Cooling Tower B_ypass Valve

On October 30,-1992, the licensee reported that both trains of the .

essential service water (ESW) system had been inoperable at

various. times since restarting from the last refueli'ng outage on

May 18, 1992.-- The licen_see identified that; valve EF HV-0066:would'

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not fully close as required _during a design basis _ accident due to-

the improper setting of the valve's close limit switch. The

valve's failure to perform its required safety function ' rendered'

. the "B" train of the ESW system inoperable since April .12,1992.

The licensee had rendered the "A" train inoperable for normal ,

maintenance and surveillance activities on several occasions

resulting in both trains of the ESW system being inoperable.

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On November 25, 1992,-- the licensee rescinded the report on the-

inoperability of the ESW "B" train based on extensive calculation '

and verification efforts. These efforts concluded'that the.ESW-

system could still perform its design function with valve EF HV-

-0066 only going to a partially closed position.

System Description

The ESW system is a safety-related system that functions to-ensure

adequate cooling flow is maintained to a number of safety-related

components needed to safely shut down the reactor during and:

following design basis accidents. The ESW system consist ofstwo

independent. trains. Each train consists of a.100% capacity pump, .

valves, and associated piping. The ESW pumps take suction from-

the ultimate heat sink (VHS) cooling pond and provide the required

flow to safety-related heat loads. The UHS system consists of one

mechanical-draft cooling tower with redundant cells (one full-

capacity cell for each independent train) and one UHS cooling

pond. Under a design basis loss of coolant accident, the UHS

system ensures that a reliable source of cooling water will'be-

available to the ESW pumps to safely shut- down and maintain the -

reactor in a safe shutdown condition. After heat has been

transferred from r afety-related loads to the ESW- fl_ow,- this flow

returrs to the UHS by one of two paths. The ESW return flow will-

either be directed to the basin of the UHS cooling _ tower or over

the VHS mechanical draft cooling tower, for additional cooling.

These flow paths are controlled by the position of valve EF HV -

0066. The temperature of the ESW return flow, which is monitored

by a temperature element embedded in the valve's wall, will

determine whether valve EF HV-0066 will remain in its normally

open position or perform its_ safety-related function to close. In

either case, the return flow collects'in the basin and later '

drains back to the VHS pond, thereby, transferring heat to the -

UHS. The maximum and tinimum temperatures of_the UHS are 95 F and

32 F, respectively.

The service water system supplies safety-related components during  ;

normal plant operation; during this time, heated service water-

return flow discharges to the circulating water system. However,

under accident scenarios, the service water is isolated, and ESW

automatically starts. _ESW flow then becomes the reliable supply

source, as- fed from the _ UHS cooling pond, to_ safety-related heat

loads such as containment coolers, diesel. generators, and

component cooling water heat exchangers. As ESW return flow

increases in temperature, but remains-below 91oF,.' valve EF HV-0066

will remain open and continue to direct' ESW return flow to the

cooling' tower basin. This system configuration results in a

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slowly increasing UHS cooling pond temperature. Elevations in VHS

temperature eventually cause an increased temperature of the ESW

supply to safety-related heat loads. As a result, the temperature-

of the ESW return flow will-increase until it reaches the

temperature limit of 91 F causing valve EF HV-0066 to

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.automatidally close. After valve EF HV-0066 closes, ESW return-

flow is forced over the UHS mechanical draft tower fill before

collecting in the basin and eventually draining to_ the UHS pond.

This increases heat _ transfer resulting in lower maximum UHS

cooling pond temperatures.

-Background

Valve EF HV-0066 must be operable for the "B" Train of the ESW

system to be operable; the valve's operability ensures that.the

temperature design limits of the UHS are not exceeded. Valve EF

llV-0066 is a-safety-related 30-inch butterfly, motor operated

valve (MOV). The licensee's verification of MOV operability, to

meet Technical Specification (TS) requirements, is accomplished by

stroke time testing and through motor operated valve analysis and

test system (M0 VATS) testing. The licensee conducts M0 VATS

testing as directed by the MOV program. Call away's . MOV - program

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was established as a result of regulatory policy and industry

concerns. Engineering Department Procedure EDP-7Z-Oll4, " Motor

Operated Valve Predictive Performance Manual," revision 4,

implements the MOV program.- The program verifies the-operability-

of valves by ensuring that safety-related valves will perform

their intended safety function. The valves are tested to ensure -

that they develop the required. thrust or torque to open;and close

against the maximum differential pressure (DP) experienced, by the

valve, under accident conditions. Thrust requirements have been-

obtained for approximately 55% of the licensee's 153 MOVs which- .

have been full DP tested. For those valves which -have not been DP

tested, acceptance criteria have been established based on other

acceptable methodologies.

M0 VATS testing determines the final-limit switch setting 'for

rising-stem valves because the disc is thrust into the seat for

these types of valves. When dealing with butterfly valves,_ to

protect against damage to_ the seating surface,_ the disc is allowed

to coast into the seat during M0 VATS testing._ Under these

conditions, the' torque produced is not significant'enough to

reveal seating of the disc when the. valve seats are soft or if the

spring pack preload is high. As a result, MOVATS testing is

unable to determine where the disc is with respect to the seat;

therefore, limit switch setting by the electricians is critical.

Seouence of Events

During a routine review of predictive performance data taken

during MOVATS testing on EF HV-0066, an engineer observed that-the

torque switch _ bypass.(TSB) was opening at approximately 1.0

second. This TSB opening time. represents only 5% of the valve's-

full stroke time of 19.4 secon'ds. Normally, the opening time for

-a TSB is approximately 20-to 25 percent of the valve's full stroke

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time; thus,- the TSB should not have opened until about 3.9

seconds. It appeared that the TSB was incorrectly set based on

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the valve's stroking time. The engineer noted that 1.0 second was

an unusually short opening time for a TSB and decided to perform

additional reviews. -The engineer retrieved the M0 VATS data taken

on the' valve prior to the outage. The MOVATS signature traces

indicated that the TSB was opening at 7.8 seconds which is

approximately 28%.of the valve's full stroke time of 27.7 seconds.

After further comparison of the two M0 VATS signature traces, the

engineer discovered the full stroke time of the valve had been-

decreased by approximately 8.3 seconds, without a documented

basis. This decreased stroking time gave the impression that the

TSB was incorrectly set when it was actually set properly.

The licensee conducted a review of the maintenance activities

performed on valve EF HV-0066 during the outage. Work request

(WR) A144691B, had instructed electricians to perform limit switch

setpoint adjustment / verification and torque switch

checkout / adjustment in accordance with-MTM-ZZ-QA006, Revision 24,

"Limitorque Actuator Limit Switch and Torque Switch Adjustment."

Section 6.6 of MTM-ZZ-QA006 delineates how limit switch

adjustments will be made and instructed the electricians to review

Attachment 4, "Limitorque MOV Limitswitch Setpoints," to determine-

the proper limit switch setpoints to be.used for setting the

rotors, Attachment 4 indicated the open and close rotor limit

switch setpoints. -The attachment also directed the electricians

to notes 3 and 12 for proper setting of the intermediate #2 and #1

rotors, respectively. Note 3 stated that the valve was a

butterfly valve, and that the intermediate #2 rotor should-be set

such that the disc would coast into the-seat after the close limit

switch contacts opened. Due to the soft seating material of some

butterfly valves, coasting of the disc into the seat minimizes

impact and damage to the seat. The procedure did not specify how

to verify that the limit switch was properly set.

On April 12, 1992, the electricians documented, on the work

completion form, that in accordance with MTM-ZZ-QA006, the

intermediate #2 rotor (close limit switch) was set at 20 hand

wheel turns from full closed. It was later discovered that this.

setting resulted in the disc not coasting into the seat, but

instead remaining approximately 25% open. The failure to set th+ -

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close limit switch for valve EF HV-0066 in accordance with

procedure MTM-ZZ-QA006 is considered an example of an apparent-

violation of NRC requirements. (483/92015-01A(DRP))

The licensee missed an opportunity to identify this error when the

electrical foreman performed his supervisory review of the

completed work package. This work activity was accomplished by

two different crews. The first crew had finished setting the

close rotor and began setting the intermediate rotor prior to

shift change. .To provide turnover information to the oncoming-

shift, the first crew recorded on the work completion form the

interim setting of the close limit switch. Because of a

miscommunication problem, the oncoming crew interpreted the

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" interim" setting of the first crew's work. as .the final setting.

The second crew realized the valve would not coast-20 turns'and

that the setting was too much, but did not modify the setting. >

According to the electricians, they thought that- this setting was

only a rough estimate which would be finally adjusted and set

during M0 VATS testing. This misconception of the capability of

MOVATS testing to determine the final limit switch setting was-

generally held by all of the electricians. The: lack of limit

switch setting verification by MTM-ZZ-QA006, the misconception of

the capability of MOVATS testing, and inadequate communications

during the electrician's shift turnover indicate that the. measures

to ensure proper setting of safety-related butterfly valve EF HV-

0066 were inadequate.

Retest and Reviews

The retests conducted to restore valve EF HV-0066 to an operable

status consisted of a full MOVATS (MTM-ZZ-QA001) test performed on

April 13, 1992, and a stroke time test per 0$P-EF-V00018, Revision

7, "ESW Train B Valve Operability" conducted on April 14, 1992.

Neither retest identified the failure of EF HV-0066 to stroke

fully closed.

The butterfly valve acceptance criteria for the M0 VATS testing.

addresses torque requirements, stroke t-ime and motor current for

the valve. The stroke time criterion only verifies that the valve

opens or closes _ in less than the allowable time. With the close

limit switch misadjusted, the valve closed in much less-than the

maximum time, but there was no requirement to evaluate this aspect

in the-procedure'. With'the close limit switch. misadjusted, the-

TSB opening time was also affected, but there was no requirement

to verify this parameter either. The tognizant quality control

test coordinator _(QCTC) for M0 VATS testing could have identified

what appeared to be an incorrect set TSB during-the~ review of

M0 VATS signature traces,- which may. have led-to earlier

identification of the problem. .Also, because the QCTC'did.not-

have the valve's previous stroke time data with him in the field,-

. he was ' unable to note the significant decrease in the valve's' full

r stroking time. The use of_ QC personnel as M0 VATS test

coordinators was implemented for the first time during the outage

to support the increased number of valves requiring M0 VATS

testing. The QCTC had received training, prior to the outago, on

how to analyze M0 VATS signature traces for incorrect TSB settings

as well as other_ abnormalities not required to be verified _per the

procedure. The inexperience of_the QCTC may have been a

contributing factor in not readily identifying what-appeared to be-

a shortened TSB opening time.

In the performance _ of the second retest, OSP-EF-V0001B, an

equipment operator (E0)- was stationed-locally at the valve to

observe valve movement while the reactor operator (RO) remotely.

operated the valve from the control room. The R0 informed the'E0

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' that valve EF HV-0066 had traveled .from fully open to fully closed

based on light indications, and the E0 visually observed stem --

travel using the valve position indicator (VPI). However, the VPI

indicated that the valve only went approximately 75% closed before

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it automatically reopened. The E0 failed to realize that although

- he observed stem travel, the valve was not stroking fully closed.

This procedure was' also performed on July 29. and October 21, 1992,

and in both cases the E0s failed to note that the valve did not~

stroke fully closed. Step 6.1.2.4 of OSP-EF-V00018 states in part

that the position of the valve, after stroking, will be determined

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by local observation. .The failure of the E0s to determine the

position of the valve in accordance with procedure .0SP-EF-V0001B

on April 14, July 29, and October 21, 1992, are considerei

examples an apparent violation of NRC requirements. (483/92015-

OlB(DRP))

In addition, the American Society of Mechanical Engineers (ASME)

Section XI engineer had reviewed the stroke time test data for EF

HV-0066 for trending purposes. At this time, the decreased

stroking time was identified and questioned; it was assumed that

the maintenance activities (i.e. packing adjustments, lubrication,

etc.) performed on the valve accounted for the-improved stroking

time. It is not clear as to what exact questions were raised and

discussed between the M0 VATS engineer and the ASME'Section XI

engineer. -The M0 VATS engineer could not recall the specific

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question of why the valve's stroke time decreased by 8.3 seconds.

If the stroke time for valve EF HV-0066 had improved by

approximately I to 3 seconds, the-above assumption could be-

supported. However, the stroke time improving from 27.7 to 19.4

seconds.is too large of a change to be attributed to valve

maintenance.

Identification of the Event

i The incorrect-setting of the close limit switch _ for . valve EF HV-

l 0066 was later identified by an engineer while reviewing data-from

j the predictive maintenance program. If the MOV program had had a >

mechanism in place that required this trending review be done in a

i more timely manner, this issue would have been identified earlier.

I' Instead, the- review was not performed until 6 months after the

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- valve was returned to service. Upon -identification of the problem

L on October 30, 1992, the licensee. tagged and placed the valve in-

l its post-accident position. An Event Review Team (ERT) was

l- convened to . evaluate the event. The_ERT meetings (three total)

were thoroug', n detailed, and in-depth. During the first meeting,

action items were established and assigned to ensure

investigations and follow-up to the event were adequate.

Licensee's Corrective Action

1. Verified EF HV-0066 stroked fully closed after correctly

resetting the close limit switch.

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2. Identified all butterfly valves which have a safety 'related

function of repositioning closed.

3. Verified -that all butterfly valves identified above were

properly set and would properly stroke to their required

positions.

4. Verified EF HV-0065 (the "A" train valve similar in function

to EF HV-0066) properly stroke closed.

5. Performed an engineering evaluation to determine the

operability of the ESW system in its as-found_-conf _iguration.

6. _During evaluations of signature traces, the MOVATS Test

will have previous baseline data with him in the field.-

7. Revised procedures MTM-ZZ-QA006, HTE-ZZ-QA001, and OSP-EF-

OSP-EF-V00018.

8. Will review signature traces, for trending purposes, within

60 days.

9. Retraining 'of appropriate personnel.

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a.) Electricians and Supervisors

b.) E0s

Safety Significance

. The licensee performed an engineering analysis of the as-four.d

condition of the ESW-system. Results indicated that the UHS

cooling pond would: reach a maximum temperature.of 102oF due to the

inability of valve EF HV-0066 to fully close. Using a combination

of design basis assumption values and actual values, the licensee

determined that the ESW was still operable and capable of

performing-its intended safety function. Based upon_the above

information,-this event posed no significant threat to the-health

and safety of the public or plant safety. However, this event Js

considered significant based upon the need to perform a detailed

analysis in the resolution of a degraded and possible non-

conforming-condition and an unanticipated reduction in the margin

of safety,

b. Overpressurization of CVCS-Piping

On October 30, 1992,' with the unit operating at 100% power, the-

chemical and volume control (CVCS) system piping was inadvertently

overpressurized, due to operator error. This overpressurization

conditica resulted in .a CVCS letdown leak and the lifting of _

relief valve (RV)-BG-8119. After the system was depressurized by-

isolating letdown flow, the RV reseated and the leak stopped.

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In response to a request from the chemistry department, the_RO was

in the_ process of aligning a boron thermal-regeneration system

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(BTRS) cation bed into service. Step 4.1.3.1 of procedure OTS-BG-

00003, "BTRS operation with Cation Bed in B Demineralizer,"

directed the R0 to place BG HIS-7054, BTRS Inlet-Valve, in auto by

depressing the " auto" pushbutton. The operator did not-depress-

the pushbutton long enough, so BG HIS-7054 failed to go to its

auto position. The procedure did not require verification of this

step nor did the operator perform a self-check of this step. -With

pushbutton BG HIS-7054 in auto, the valve should have

automatically open after BTRS control switch, BG HIS-27, was

placed in the dilute mode; thus, providing an alternate letdown

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flowpath after closing the CVCS demineralizer outlet isolation -

valve, BG HV-8245. However, after BG HIS-27 was placed in dilute,

the valve remained closed since BG HIS-7054 was not in auto. This

discrepancy could have been identified if either the procedure had

required verification of this step or if the R0 performed a self-

check. To establish flow through the BTRS cation bed, BTRS

demineralizer bypass valve BG HV-387 had to be closed. This bed

flow could then be monitored through a flow meter' downstream of

' the bed. Again, verification of flow rate was not required by the

procedure and a'self-check was not performed by the operator.

With both the normal and alternate flowpaths downstream of the

CVCS demineralizers isolated, by having BG HV-7054 and_BG HV-8245

both closed, a-dead head of the system occurred. As a result,

upstream CVCS piping-was overpressurized causing a letdown leak

. and the lifting of RV BG-8119 which has a setpoint pressure of 278

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psi. This RV is located downstream of backpressure control' valve

BG PCV-01312, and relieves to the volume control tank (VCT). This-

condition went unnoticed, by the operating crew, for approximately

an hour and a half. In the meantime, the licensee had entered

technical specification 3.4.6.2 due to a decreasing trend in VCT

level. The leak was later quantifi_ed at 1.7 gpm.

During a. shift change, the on-coming R0-identified _ the

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overpressurization condition after monitoring the flow meter

downstream of the valved in BTRS cation bed which indicated-a flow

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rate of zero gallons per minute-(gpm); monitoring' letdown flow .

downstream of the letdown heat exchanger (LHE) which was normal;

and observing VCT level, which was decreasing. The R0 isolated

letdown to depressuri7e the system by closing the' letdown orifice

isolation valves and diverting system piping flow-to the VCT. Due

to increasing particulate readings in the auxiliary building, an

E0 was dispatched to locate the suspected leak. He later informed

the control room of a fine steam mist coming from room 1308C which

houses several CVCS demineralizers. .The area was roped off and

posted by health physics (HP) to prevent unauthorized entries.

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After the system was depressurized, HP and operations developed a-

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plan to get the appropriate personnel properly suited-up to enter

the area and identify the leak. However, upon entry into the-

room, the E0s were unable to identify the leak even after the -

system was restored to normal operating pressure.

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After verifying the leak had stopped, the. RO restored letdown

flow. During this evolution, the R0 had to nearly close back

, pressure valve, BG PCV-0131 before system pressure and _ letdown

flow was achieved. This occurred because the system piping had

drained more than the operators had expacted and low piping

pressure. This condition resulted in voiding of system piping;

thus, when letdown was reestablished, flashing occurred. Prior to

restoring letdown flow, RV BG-8117, which discharges to the

pressurizer relief tank, lifted inside containment. This RV has a

setpoint pressure of 600 psi and is located downstream of the LHE.

Upon restoring the proper CVCS configuration, a reactor coolant

system balance inventory indicated an acceptable leakage rate of

.35 gpm.

No waterhammer was heard or reported, but since there was evidence

of voiding in the line, the licensee performed a transient

walkdown procedure to verify that waterhammer damage had not

occurred to system piping inside containment. -An event review

team (ERT) was later convened to review and evaluate the event.

The root cause identified by the ERT was consistent with what was

identified by the resident inspectors.

. c. Failure of Inverter NN14

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On November 26, 1992, at 5:46 pm, inverter NN14 failed causing. bus

NN04 to lose power. NN04 is one of four channels of safety-

related 120 Volts AC instrument power. The operators determined

which bus failed and ensured that any instruments controlling

operating parameters were not selected as the controlling channel

(commonly referred to as selecting away). Procedures were brought

out for reference and subsequent actions followed. No reactor or

secondary side operating parameters experienced any significant

change.

The loss of voltage to bus NN04 caused the suction of the charging

pump to switch from the volume control tank (VCT) ta the refueling

water storage tank (RWST) and for the thermal barrier flow to be -

isolated. The suction path was manually returned to the VCT and

the proper amount of diluted water added to the RCS to ensure that

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no power level changes were experienced.

The backup safety-related transformer XNN06 (commonly referred to

as the SOLA transformer) was energized and utilized-to re-energize.-

bus NN04. Subsequently all instrument channels and signals

a returned to their normal status._

The 'iicensee called out the system engineer and began

troubleshooting efforts. The ferroresonant transformer, internal

to the inverter, and some capacitors were changed out_while the

a waveform output was monitored. The licensee did not positively.

discover the root cause of the transformer failure but did succeed

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in returning the waveform output to normal. Since the root cause

was not definitively identified, the licensee wanted to test the

vital inverter for about 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> under load prior to returning it

to service. However, the time limit of the technical

specification action statement had almost expired.

TS 3.8.3.1.f requires, in part, that 120 volt vital AC bus NN04 be

re-energized within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and that within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> it be

energized from its associated inverter. When bus NN04 was

energized from the SOLA transformer, the licensee complied with

the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> action statement. During troubleshooting efforts the

licensee could not re-energize bus NN04 from its associated

inverter and this meant that the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement was

still in ef fect. Troubleshooting efforts by the licensee were

difficult and time consuming. On November 27, 1992, at about 3:30

p.m., the NRC granted the licensee a temporary waiver of

compliance and extended the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement to a total of

48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The licensee had performed the necessary repairs to the

vital inverter but wanted additicnal time to place a test load on

the vital inverter to ensure that all necessary repairs had been

implemented.

On November 28, 1992, at about 1:16 a.m., the licensee re-

energized Bus NN04 from its normal safety-related power supply and

restored all equipment to its normal status. TS 3.8.3.1.f was i

exited at that time.

Conclusion

The lack of limit switch verification required by procedure MIM-ZZ-QA006

to ensure proper setting of the close limit switch is an example of an

apparent violation of NRC requirements (50-403/92015-01A(DRP)). In

addition, the licensee's failure to ensure E0 compliance with OSP-EF-

V00018 on three occasions is also an apparent violation of NRC

requirements (50-483/92015-OlB(ORP)). Although adequate corrective

action was taken for the overpressurization event, the failure of the

reactor operator to ensure valve BG HV-7054 was in auto is another

example of weaknesses in the area of procedural compliance. This

example combined with the improper verification of valve position

indicate that additional management resources are needed in this area.

3. Plant Operations (71707)

The objectives of this inspection were to ensure that the facility was

being operated safely and in conformance with license and regulatory

requirements and that the licensee's management control systems were

effectively discharging the licensee's responsibilities for continued

safe operation. The methods used to perform this inspectiun included

direct observation of activities and equipment, tours of the facility,

interviews and discussions with licensee personnel, independent

verification of safety system status and limiting conditions for

operation (LCOs), corrective actions, and review of facility records.

12

_ _.

.

.

. Areas reviewed during this inspection included, but were not limited to,

control room activities., routine surveillances,:enginee' red safety

feature operability, radiation protection controls, fire protection,

security, plant cleanliness, instrumentation and alarms, deficiency

reports, and corrective actions.

a. Failure To Lock Valve BG V-0027

.

'

On November 15, 1992, during a tour of the auxiliary building, the-

resident inspectors found valve BG V-0027, "CVCS MB Demin A Pri

Sluice Water Supply Isolation" not in its required. locked closed

position. _The valve was closed and had a locking device (LD)

attached to one of the connecting wir'es. However, the other-

connecting wire was not connected to the LD and the LD was not

secured to the handwheel to prevent valve movement.

On August 3, 1992, workman's protection assurance (WPA) #4491 was

hung to perform a resin changeout and inspection. This work

activity.was performed under generic work request #G510425. The

WPA was generated per OTS-XP-00002, Revision 1, " Computerized WPA

System." In generating _WPA #4491, it appears that the R0 failed

to specify that the valve be restored to its normally locked

closed position on the tagout continuation sheet (TCS).

Additional reviews also failed to identify the error prior to

approving the tagout. In accordance with the-TCS, valve ~BG V-0027--

was tag #4 of local control WPA #4491 and was required.to be

restored only to a closed position. The E0: removed the tag,-

closed the valve, and initialled the TCS as required by procedure;

another E0 independently verified proper restoration of BG V-0027

since the valve is safety related. The tag was cleared on

November 12, 1992, as indicated-by the TCS. As required-by.

Attachment 1 of 00P-ZZ-00004, Revision 14, " Locked Component -

Control," valve BG V-0027 is to be maintained in a locked closed

position.

After the resident inspectors informed the on-duty shift

supervisor of the locked valve discrepancy, 'an E0 was dispatched

4

to investigate the valve's as-found position. A_new locking

device was properly placed on the valve at this time. The valve's

as-found configuration was not discussed in the shift turnover

sheets, nor was _ a Suggestion, Occurrence, and. Solution' (S0S)'

_

generated to address.the incident. On November 17, 1992, an EO-

identified that valve AP V-0001, " auxiliary feed pump mini-flow to

condensate storage tank," was open but~not locked as required.-

This valve's condition was identified during a surveillance -

pr.ocedure and subsequently documented in an S0S. These two

examples of improperly restored valves demonstrate the need for

>

additional management attention in this area. The licensee's

failure to restore valve BG V-0027 to its required locked closed

position is a violation of NRC_ requirements-(50-483/92015-

,

02(DRP)).

l 13

4

= rrr--a ,, . - , . , _ - , - - . , . , - . - ......-.y m_.,.- r. _, m-.,_, r ,,,_.y , ,, ,....-. _..~.,,-.- ,,,. - .,, . -- ._~. , m , ,--_.-

_ - - _ - _ _ _ _ _ _ _ _ _ _

r

.

i

b. Inadvertent RCS Dilution

On October 14, 1992, Instrument and Control (I&C) personnel-

requested the control room to initiate a purge of radiation

monitor SJ RE-00001, Reactor Coolant System Letdown Process

Monitor. I&C was scheduled to perform a surveillance on the,

radiation monitor and wanted to ensure that no foreign material

was inside the monitor causing it to read radiation above normal

bacAground levels. I&C requested that the monitor be purged for

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. At approximately 10:27 a.m., the monitor was placed in

the purge mode. When the radiation monitor is placed in the purge

mode, clean water from the reactor makeup system is passed through

the monitor, flushing out any easily removable particles. The

length of time that the monitor is in the purge mode varies and is

determined by the operator manually changing the setpoint. During

this evolution, the purge cycles were set so that about 10 gallons

of water would pass through the chamber during each purge. During g

the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the monitor was purged 10 times. At the end of

the tenth purge cycle, the RO noticed that the RCS temperature had

increased about one degree to 589.3oF. The R0 borated the RCS (

back to its normal temperature.

The purge portion of SJ RF~00001 normally discharges purge water

into the volume control tank (VCT). The VCT is the suction point

for the charging pumps. The charging pumps supply the seal

injection flow for the reactor coolant pumps and supplics makeup

to the RCS. Some seal injection water flows into the RCS. The

pure water being added to the VCT thus flowed into the RCS causing

an inadvertent boron dilution.

The licensee issued a night order to ensure all operators were

aware of the purge path. In addition, I&C modified the

surveillance procedure and task sheet to include information that

a dilution is possible. -

c. , Review of Of f-Normal Operating Procedures

During this inspection period, the inspectors performed a review

of the licensee's procedures for responding to off-normal events.

During the special inspectio.. following the licensee's loss of

control room annunciators event, the inspectors had noted that the

licensee lacked an of f-normal operating procedure. The inspectors

evaluated the licensee's off-normal operating procedures in an

effort to identify any other conditions for which an off-normal

operating procedure did not exist.

The licensee designation for off-normal operating procedures is

OTO. The inspectors reviewed the OT0s and compared them to the

OTOs at five other similar utilities. This comparison identified

several areas in which there were apparent gaps. These areas were

loss of power events and events occurring while the unit was

shutdown. *

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14

,

- _ - - _ - - _ - _ _ - - _ _ _ _ _ _ , _ _ - , _ _ _ _ _

. . ,. .

.

,

-The inspectors reviewed normal operating procedures =(0TNs) and

special' operating procedures (OTSs) and determined that all-

apparent _ gaps identified above did have. procedures addressing

~

these events. However, while the necessary information appeared-

to be available in these other procedures it was unorganized,

disjointed and difficult to retrieve. In addition, OTOs generally .

contain diagnostic steps, immediate action steps and restoration

steps not always contained in the other' procedures. .An example of-

this would be the loss of a 120 Volt AC instrument bus. Recently,-

the procedure was re-written for this event, but previously the

operators had to remember that in an attachment to the normal .

operating procedure was a listing of what instruments and controls

,

would be affected during a specific bus loss.

The licensee was in the midst of a major revision of the

procedures concerning response to control room annunciators.

However, no effort was being expended to revise and update the

OTOs. The inspectors held discussions with licensee management ~in

-

which the licensee' agreed that the OTOs should be evaluated and

modified as necessary.to ensure that the operators have sufficient

guidance for plant events. The licensee' stated that the OTO

procedure revision would be evaluated and the schedule adjusted to

more promptly review and rewrite the OT0s.

Conclusions

The failure to restore the valve lock is a violation (50-483/92015-02).

I&C technician and reactor operator-unfamiliarity with the-purge

-path'of a radiation monitor resulted in an inadvertent RCS boron

dilution.

4. Maint aance/ Surveillance (62703) (61726)

Selected portions of the plant surveillance, test, and maintenance

activities on safety-related systems and components were observed or-

reviewed to ascertain that the activities were performed in accordance

~

with approved procedures, reguletary guides, industry codes and

standards, and the Technical Specifications.- The~following items were

considered during these inspections: the limiting conditions for

operation were met while' components or-systems were removed from

service; approvals were;obtained prior to initiating.the worL;

activities were accomplished using approved procedures .and were

l inspected as applicable; functional testing and/or. calibration was

perforn d prior to returning the componentsLor systems to service; parts

and matei tals that were used were properly certified; and appropriate

-

fire prevention, radiological, and housekeeping conditions were

p ' maintained.

a. Maintenance

The reviewed maintenance activities included:

15

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_ _ . _

y

'

Work Reauest-No. Activity

W155328- Repaired inverter NN12.

W498643 Replaced torque switch in valve .BN HV-

00004.

W150554 "A" diesel generator "B" air compressor .-

low capacity.

W522501 Replaced unloader valves in control room

air conditioner "B".

W147551 Repaired ' fuel pool cooling heat exchanger-

"B" tube side outlet valve.

W518422 Replaced drain valve, V KC-100SE, of fire-

water storage tank "A".

G523765 Replaced gasket in 68 high pressure heater

standpipe.

On November 17, 1992,-the licensee repl' aced 'the ferroresonant

transformer in the NN12 inverter. Initial problems with the

inverter were identified by an equipment operator, on November 14,

1992, when unusual noises were heard coming from the inverter.

All level controlling channels were selected away from NN02 in the

. control room. This action was a precautionary measure taken in

case of-the loss of NN02 bus due to NN12 inverter failure.

Replacement activities were performed under_ Work Request _W155328

while the vital instrument bus, NN02, was fed from the backup

transformer XNN06. A representative from the vendor was onsite to

assist the system engineer (SE) in troubleshooting efforts and

retest activities. The repair activities were. performed in an

organized and controlled manner. During this time, the SE-

identified, through the use of thermography, that several

components had experienced excessive heating. Also, one component -

had loose solder connections, and one meter was defective. A

planner was requested to-make the necessary changes to the WR to-

allow replacement of these components,

b. Surveillance

The reviewed surveillances included:

Procedure No. Activity

ISF-GN-0P937 Functional test of containment pressure

loop _GN-P937.

16

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. -

d

1. OSP-NE-00002 "B" stand-by' diesel generator _60 second-

load test.

ISL-NF-NB020 Calibration of potential- transformer ; <

, bistables (grid degraded voltage signal).

ISL-GS-00A2A Containment hydrogen analyzer train "A"

loop analysis.

ITL-EF-000P1 ESW pump "A" discharge pressure loop

_

calibration.

MPE-ZZ-QA001 Partial M0 VATS testing of limitorque motor

operated valve on BN HV-8812B.

ESP-ZZ-00006 Incore/excore calibration.

ETP-SR-00020 Flux and thermocouple mapping.

ISF-GN-P937 was utilized to perform an Analog Channel Operational

Test (ACOT) of one of four containment pressure instrument

channels. Prior to placing the channel.'in " test" the I&C

personnel received proper permission to perform the test-and ~

verified that no other containment _ pressure channels were in

" test". All indications were found within required tolerances and -

as-left readings were the same as the-as-found readings.

,

Conclusions

The observed maintenance and surveillance activities were well performed

by the licensee.

No violations or leviations were identified.

6. Exit Meetina (71707)

The inspectors met with licensee representatives-(denoted under Persons ,

Contacted) at intervals during the inspection-period. The' inspectors

summarized the scope and findings of the: inspection. The licensee

representatives acknowledged the findings as reported-herein. The

L

inspectors also discussed the likely. informational-content of the

inspection report with regard to documents'or processes reviewed by.the

inspectors during the inspection. The-licensee did not identify any:

such documents / processes as proprietary.

p

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17