ML20197G619

Insp Rept 50-458/97-17 on 971012-1129.Violations Noted. Major Areas Inspected:Operations,Maintenance,Engineering & Plant Support

ML20197G619
Person / Time
Site:	River Bend
Issue date:	12/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20197G599	List: IR 07100012/2011029 ML20197G595 ML20197G619
References
50-458-97-17, NUDOCS 9712310074
Download: ML20197G619 (19)

See also: IR 05000458/1997017

Text

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ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV -

Docket No.: -50-458

Ucense No.: NPF 47

Report No.: 50-458/97 17

Licensee: Entergy Operations, Inc.

Facility: River Bend Station

Location: 5485 U.S. Highway 61

St. Francisville, Loulslana

Dates: October 12 through November 29,1997

G. D. Replogie, Senior Resident inspector, incoming  :

Inspectors:

W. F. Smith, Senior Resident inspector, outgoing

' Approved By: E. E. Collins, Chief, Bra'e.h C 3

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Divisioti of Reactor Projects

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Attachment: Supplementalinformation

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EXECUTIVE SUMMARY

River Eend Station

NRC Inspection Report 50-458/97-17

This inspection included aspects of licensee operations, maintenance, engineering, and plant

support. The report covers a 7 week period of resdent inspection.

QDEah0D3

• The plant startup on October 19,1997, was conducted iri an ordedy manner and in

accordance with proceuural requiren,0nts. The control room supervisor demonstrated

good command and control during the evolution (Section 01.1).

- A nuclear equipment operator misoperated the system. Consequently, the suppression

pool cleanup system was damaged. This condition ultimately resulted in aggravating a

p: ant conductivity excursion. Other contributing factors to the event included inadequate

training, validation of the system operating procedure, and information turnover

processes. A poor questioning attitude and a lack of safety focus on the part of the

nuclear equipment operator were ad htional contributing factors to the event. The

inspectors deter:nined that the licensee's investigation into the conductivity excursion

failed to Mentify the operations related issues (Section 04.1).

• ,9ubsequent to the failure of a containment sir lock overallleak rate test, the operations

shift superintendent (OSS) entered the wrong Technical Specification (TS) ACTION

Statemeht (Section M1.4).

• After the appropriate ACTIGN Statement was enterev ' ir an inoperable air lock,

operators failed to initiate actions to ensure that the os. rall containment leakage rate

(using air lock test results) did not exceed that permitted by TSs (Section M1.4).

Maintenance

• The inspectors r sted multiple instances where maintenance and/or surveillance activities

were delayed or had to be rept sted. The causes for these problems were (1) poor

coordination and preparation for maintenance and/or testing; (2) questionable

understanding of design; (3) a less than expected questioning attitude; or (4) failure to

adhere to procedural requ;rements. This has been noted to be a continuing problem

(Section M1.2).

• Some procedures governing localleak rate testing for containment isolation valves were

inadequate because testing was specified with lift check valves in the air pathway. In

some cases, the test configuration resulted in unacceptably low test pressures, while in

other cases the effects of the test configurations were not known. Corrective actions to

address this finding were coroprehensive (Section M1.3).

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• During local leak rate testing, maintenance technicians failed to vent the leak rate ,

monitor bypass manifolds, as specified by the procedure. This was the second time that

a leak rate monitor bypass manifold venting problem was identified in the past 2-months 3

(S6ction M1.4). .

• Mechanical maintenanca department personnel inappropriately deferred the overall air ,

lock leak rate test until after startup without considering how the use or maintenance of

the air lock could have affected its operability. This was an example of poor change

management, as this responsibility was recently transferred from engineering to

maintenance (Section M1.4),

Plant material condition was generally acceptable. Concems were identified with

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damaged drywell insulation, the inoperable SPC mode of the alternate decay heat

removal (ADHR) system, an inoperable postaccident sampling system, excessive main

generator hydrogen leakage, an inoperable spent fuel cooling pump, and t, degraded

control rod drive (CRD) pump (Section M2.1).

a Magne-blast breakers, associated with the high pressure core spray (HPCS) diesel

generator switchgear, were not refurbished on a periodicity consistent with industry

recommendations. Planned corrective measures were acceptable (Section M8.2).

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Enginitttdag

• The engineering disposition of the residual heat removal (RHR)line break annunciation

under maximum extanded load line allowance (MELLA) conditions was acceptable

(Section E2.1),

Plant Sucoort ,

. Health physics personnel did not meet management expectations because drywell

entries were permitted while the traversing in-core probe system was not danger tagged

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off (Section R1.1).

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Report Details

Summarv of Plant Status

At the beginning of this inspection period, the plant was in Cold Shutdown (Mode 4), nearing

completion of Refueling Outage 7. On October 21,1997, at 6:33 p.m., the main generator was

synchronized to the power grid, signifying the end of the 39-day refueling outage. By

October 25, power was retumed to 100 percent where it essentially remained through the end of

the inspection period.

I.Qgerations

01 Conduct of Operations

01.1 Ettactor Star. tup

a. Insoection Scone (71707)

The inspectors observed the reactor startup to criticahty on October 19.

b. Observations and Findinas

The startup was conducted in an orderly manner and in accordance with procedural

requirements. The control room supervisor demonstratea goo <1 command and control

during the startup. Criticality was achieved consistent with the estimated critical rod

position predicted by reactor engineering.

c. Conclusions on Conduct _of OoeratiQDS

The plant startup was conducted in an orderly manner with the control room supervisor

demonstrating good command and control during the evolution.

02 Operational Status of Facilities and Equipment

02.1 Enoineered Safety Featt.re System Walkdowns (71707)

The inspectors walked down accessible portions of the following

safety-related systems:

• HPOS System

• Diesel Generators 1,2, and HPCS

- RHR System, Trains A and B

+ Containment, including the drywell

- Reactor Core Isolation Cooling (RCIC) System

The systems were found to be properly aligned for the plant conditions and in acceptable

material condition,

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' Prestartup Drywell Walkdown: The inspectors accompanied a reactor operator during  :

the performance of the drywell closeout inspection. The operator performed the 1

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inspection in accordance with procedural requirements in a satisfactory manner. The

inspectors noted that the drywell cleanliness was acceptable.' Some minor

items were noted during the walkdown (paint chips and tie wraps), however, the ,

inspectors considered the amount of debris minimal and not sufficient to affect the  ;

operability of emergency core cooling systems (ECCSs). The licensee removed the '

identified items prior to startup.

04 Operator Knowledge and Performance t

- 04.1 Nuclear Eauloment Ooerator (NEO) Performance l

a. lasoection Scone (71707)

The inspectors performed a review to determine the causes related to a damaged valve

used in the SPC mode of the ADHR system (SPC AOV 51, SPC backwash valve). The

inspection identified several NEO training and performance issues not previously

addressed by the licensee,

b. ' Observations and Findinas - f

On October 23, an NEO attempted to perform a manual backwash of the SPC filter in

accordance with System Operating Procedure 0140, " Suppression Pool Cleanup and

Alternate Decay Heat Removal," Revicion 3. The NEO was unable to accomplish the

task in accordance with the system operating procedure because Valve SPC-AOV 51 ,

_ (SPC filter to backwash tank outlet valve) was interlocked closed. Instead of stopping

when confronted with an unexpected condition and contacting his supervisor, the NEO

proceeded to open Valve SPC AOV 51 ten different times (each time it immediately

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closed after it opaned) until the backwash was accomplished. After the evolution, a

" backwash tank not dry" alarm occurred, indicating that the backwash tank was not empty

(it should have been empty). The NEO assumed that the alarm was due to an instrument

problem and did not implement Annunciator Procedure AOP SPC-PNL200, Revision 0,

which required the opening of backwash Tank Drain Valve SPC-AOV-79.

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Subsequent to the backwash, Valve SPC-AOV 51 was leaking at a substantial rate.

Furthermore, since Valve SPC-AOV 79 was closed, water flooded the backwash tank,

demister, and portions of the radwaste ventilation system ducting. This problem was not

identified until operatois attempted to operate the radwaste ventilation system in support

of a reac'or water cleanup (RWCU) demineralizer backwash on October 24. The

, ventilation system repeatedly tripped off, on high vacuum, and delayed replenishment of

the A RWCU demineralizer. This delay aggravated a reactor vessel conductivity

excursion, with conductivity peaking at approximately 8 uS/cm (normal conductivity is less

than 1 uS/cm).

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The inspector considered the following to be contributors to the events:

• The NEO had not been given hands-on training prior to being asked to operate the

system. Whe the NEO had completed the classroom portion of the training, the

'nds-on training was not conducted until October 27,4 days after the NEO

atiempted the backwash.

• The system operating procedure was not appropriately validated before it was

provided to the operations department for use.

• A condition report (CR) concerning the problem with the procedure

(Valve SPC AOV 51 interlocked closed) was written 5 days prior to the

NEO's attempt at a backwash, but the NEO was not provided this information

during shift tumovers. Additionally, the licensee had no process in place to ensure

that the NEO would have become aware of the problem prior to attempting a

backwash.

• The NEO did net stop when he found tha' he couldn't proceed in accordance with

the procedural requirements. His decision to continue was in direct conflict with

his training and demonstrated a poor questioning attitude and safety focus.

. The NEO mistakenly assumed that the " backwash tank not dry" alarm was caused

by an instrument problem and did not follow the requirements of the annunciator

procedure.

The licensee had also investigated the event, but focussed only on the adequacy of the

system operating procedure and on making repairs to Valve SPC-AOV-51. The NEO's

actions were not specifically addressed. Furthermore, prior to the inspectors questioning

the NEO's actions, late in the report period, Operations management was unaware of the

NEO's contribution to the valve failure.

Since the SPC mode of the ADHR system is not safety related, ro violation of NRC

requirements occurred. However, the inspectors had concerns with the performance of

operations with respect to procedure compliance, adequacy of training, and procedure

validation,

c. Conclusions

An NEO misoperated the SPC system. His actions resulted in damage to a system valve

adversely affecting the SPC mode of the ADHR system and aggravating a plant

conductivity excursion. Other contributors to the event included inadequate training,

inadequate validation of the system operating procedure, inadequate information turnover

processes, and a poor questioning attitude and safety focus on the part of the NEO.

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ll, Maintenance

M1 = Conduct of Maintenance

- M1,1 General Comments

a. Inmaaction Se (61726. 62707)

The inspectors observed portions of the following maintenance and surveillanos activities

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+ .-. STP 110-0101, " Turbine Overspeed Protection System Operability Test"

-+ . mal 314541, " Containment Air lock Door Equaliang Valve Repairs"

+. . STP-057 3704, " Primary Containment Air Locks Overall Leakage Rate Test"

+ STPs 209-3807,' 209-3818,200 3854, and 403 7301, various localleak rate tests

(LLRTs)(documentation review). .,

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• STP-050-0702i" Refueling Outage Reactor Pressure Vessel inservice Leakage

Test "(documentation review) _

+ STP-309 0602, " Division ll ECCS Testing"

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+ STP-204 4802,"RHP System Isolation Logic System Functional Test,"

(documentation review)

+ . OSP-0501, " Turbine Testing," (documentation review)

+ SOP 0140, " Suppression Pool Cleanup and Altemate Decay Heat Removal,"

(documentation review)

+ STP-209 6310, "RCIC Quarterly Pump and Valve Operability Test,"

- (documentation review)

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+ STP 203-6305,'*HPCS Quarterly Pump and Valve Operability Test,"

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' Maintenance and surveillance implernentation and coordination problems are discussed

- in Section M1.2, Adstionally, local leak rate testing issues are addressed in Sections

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M1,3 and M1,4.10perational problems associated with the HPCS system mirimum flow

valve are documented in Section M1.5.

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M1.2 Assessment of Outage Maintenance and Surveillance Activities

a. Insoection Scope (61726)

The inspectors performed an assessment of the maintenance and surveillance activities

_ performed during the outage and startup.

b. - Observations and Findings

During the outage, the inspectors noted multiple instances where maintenance and/or

surveillance activities were interrupted, delayed, or had to be repeated due to: (1) poef

coordination and preparation for maintenance and testing; (2) questionable understanding

of design; (3) a less than expected questioning attitude; and (4) failure to adhero to

procedural requirements. Examples are provided below:

• While establishing initial test conditions for Procedure STP 050-0702, " Refueling

Outage Reactor Pressure Vessel inservice Leakage Test," Revision 1, operators

experiencr'd two problems. First, operators were having difficulty achieving

the specified test temperature in the reactor vessel head. Through further

investigation, the licensee found that much of the head insulating material had not

yet been instailed. After the insulation material was installed, the correct head

temperature was achieved. Second, operators were not able to establish letdown

flow through the RWCU system because a downstream valve (Valve DTM V 279,

a manual letdown isolation valve) was tagged in the closed position for

maintenance. When initially attempting to establish letdown, Relief

Valve G33-RV036 lifted due to condensate piping system pressure. Operators

- rerouted the letdown to the radwaste system until an appropriate relief pathway

was established.

• While implementing Procedure STP 309-0602," Division 11 ECCS Testing,"

Revision 12 (ECCS/ Loss of Power / Loss of Coolant Accident Test Initiation), an

instrument and controls technician failed to reposition two undervoltage test

switches in accordance with the procedural requirements. The procedure required

the test switches to be opened (which was accomplished) and then immediately

reclosed (which was not accomplished). Consequently, loads did no! sequence

onto the diesel generator and the test had to be reperformed. in response to the

failed test, the licensee identified that the technician did not have the procedure

with him during the test (and did not remember the appropriate sequence of test

switch manipulations).

As corrective measures, the licensee, in part: (1) counseled the technician

regarding the requirement to have procedures in-hand during the performance of

surveillance; (2) reinforced the proper use of procedures with all site personnel;

and (3) counseled the ECCS test director concerning the importance of discussing

key steps during pretost briefs. The corrective measures were acceptable. The

failure to perform the surveillance in accordance with the procedural requirements

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was a violation of TS 5.4.1.a. which requires the licensee to implement procedures

recommended by Appendix A of Regulatory Guide 1.33. The Regulatory Guide

recommends procedures for surveillance testing. However, this nonrepetitive,

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

consistent with Section Vll.B.1 of the "NRC Enforcement Policy "

. (NCV 50-458/9717-01).

• While performing Procedure STP 204 4802,"RHR System isolation Logic System

Functional Test," Revision 7, which, in part, ensured that certain containment -

isolation valves would isolate upon initiation of a test signal, two containment

isolation valves in the ADHR system unexpectedly isolated (Valves RHS AOV 63

and RHS AOV 64). These containment isolation valves were part of the ADHR

system modification that was recently made operational. The licensee later

determined that the valves operated as designed but the pro:.edure had not

appropriately included the valves within the scope of testing. The steps necessary

to test the valves had been inappropriately included in Procedure STP 309 0602,

" Division ll ECCS Testing " which was not the appropriate procedure for these

particular tests; At the conclusion of the report period, the licensee had not

determined the root cause of the procedural oversights. This is considered an

unresolved item penjing further NRC review of the licensee's root cause

evaluation (URI 50-458/9717 02).

. While establishing initial conditions for Procedure OSP 0501, " Turbine Testing,"

- Revision 40, operators reported difficulty achieving the required test conditions

(Iow pressure turbine exhaust temperature of at least 100'F). The test was

delayed for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before a waiver to the requirement was

obtained from General Electric. This was considered an example of poor planning

because the came problem occurred during Refueling Outage 6.

• When an operator repositioned to open the RCIC injection valve during stroke

time testing, the valve automatically repositioned closed, which surprised the

operator. The RCIC valve had operated as designed (isolate on high reactor

water level) but the operator was not aware that plant conditions would cause this

to occur during the test.

Additionally, during the previous inspection report period, the inspectors had noted other

problems that were also attributable to similar performance deficiencies as provided

below:

• - Scram time testing of control rods was performed with a 1/2 scram signalin. At

the time of the testing, operators did not consider, or question, the effect of the

1/2 scram signal on the test. After testing was compW, the licensee determined

that the testing was invalid and would have to be reperformed (See NRC

Inspection Report 50-458/9714).

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• Engineering and operations personnel failed to consider information on the " time

to aci!" curves when performing initial testing of the ADHR system Additionally,

several of the procedures were found to be inadequate. As a result, Operational

Mode 3 was inadvertently entered while several TG limited condition of operation

(LCOs) were not met (See NRC inspection Report 50-458/97-15).

• Operatins inappropriately re-energized the breaker for Valve RHR-V 9, (while

performing a breaker alignment in accordance with an approved breaker

alignment sheet). As a result, shutdown cooling was inadvertently secured when

the valve automatically repositioned to the closed position (See NRC Inspection

Report 50-458/9715).

c. C.G[usions

c The inspectors noted multiple instances where maintenance and surve91ance activities

were interrupted, delayed, or had to be repeated due to: (1) poor coordination and

preparation for maintennce ano testing; (2) questionable, inderstanding of design; (3) a

less than expected questioning cttitude; and (4) failure b adhere to procedural

ree:virements. One noncited violation was identified for the failure to follow ECC9 '*st

proceduren. One unresolved item was opened addressing ths unexpected, but

appropriate, isolation of two ADHR valves during containment isolation valve tt. u 3

M1.3 LLRTs

a. Innection Scoce (61726)

The inspectors performed a review of the licensee identified findir.g that certain LLRTs

may have been invalid due to an ineppropriate test configuration.

b. Observations and Ein@gs

As documenteo in CR 97-1727, da%d October 3,1997, the licensee identified that a Lift

Check Valve E12 VF061 was in the test pathway for Valve E5 eMOV-F013,"RCIC

Inbetion Valve and Containment Isolation Valve." Further investigation identified that

similar test configurations were also utlized for Valve G51-MOV-F077, "RCIC Steam

Line Evhaust to Suppression Puol isolation Valve," and Valve 1E51-MOV-F019,

" Minimum Flow Line Return to Suppression Pool." The test consguratii n was of potential

concern because the resultant differential pressure (dp) drop across t"e check valves

could result in unacceptably Icw test pressures at the valve seats (potentially reducing the

pressure at the valves to less tbm P ,7.6 psig).

The licensee a,sa identified that Valves E51-MOV-F077 and E51 MOV-F019 were

incorrectly tested during the last six refueling cutages while Vat e E51-MOV-F013 had

been incorrectly tested during the previous two outages. !n oice; to assess the validity of

some of the previous tests, the licensee performed testing to determine the cctual loss

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- across the check valves For Valve 1E51 MOV-F077, the dp across the check valves

(two in this case) was approximately 3.4 psig. As such, the test pressure at

the valve was only 4.6 psig, which was unacceptable. The actual test pressure at

Valves 1E51-MOV-F013 and E51-MOV-F019 could not be determined, so the licensee

consideted previous tests invalid The cause of the deficient procedural guidance was

determined to be inadequate technical knowledge on the part of procedure writers,

reviewers, and test engineers.

In response to the findings, the licenke changed the test procedures to specify a more

appropriate test pathway for the affected valves. Addnionally, the tests were reperformed,

where necessary, and all valves were found to have acceptable leakage rates. Finally,

procedure writers, reviewers, and test engineers invalved with LLRTs were appropriately

sensitized to the identified problems.

The inspectors considered the licensee's corrective measures to address CR 97-1727 to

be acceptable but noted that a similar issue was identified previously. Specifically, on

July 22,1997, with tne plant at 100 percent power, the licensee identified that the test

configuration for Valves HVR AOV-123 and HVR-AOV-165 included a lift check valve in

e the test pathway, in response to that finding, the licensee reperformed the LLRTs in an

z. appropriate manner end found leakage to be acceptable. Additionally, tests were

JC conducted to determine the actual dp across the suspect check valve. The dp across the

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check valve was sufficieritly low so that the previous test remained valid. Finally, the

i licensee performed a cognitive review of valve line-ups for approximately 50 percent of

the containment isolation valve t LRTs. Based on the results of the sample, the licensee

had concluded tnat r,o similar problems existed. ,

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Although the licensee had not performed a comorehensive review of all of the LRT

procedures after initially finding an inappropriate test configuraticn on July 22,1997, the

inspectors considered the licensee's review and corrective measures to be reasonable at

the time. Additionally, the licensee maintained an awareness of tae potential problem and

continued to scrutinize tests as they were peiformed. When additional problems of the

sarne nature were found, the licensee appropriately expanded the scope of the corrective

actions and effectively addressed the problem. The time delay between the initial finding

and subsequent findings was considered minimal and, overall, corrective actions were

acceptable,

The procedures associatad with the above tests were considered inadequate, as they

specified testing in an inappropriate test configuration. This was considered a violation of

TS 5.4.1, which requires the licensee to have and implement procedures for all programs

specified in TS 5.5. TS 5.5.13 requires the licensee to have a " Primary Containment

Leakage Rcte Testing Program." However, this licensee-identified eld corrected violation

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

Enforcement Policy,"(NCV 50-458/9717-03).

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c. Conclusions

A noncited violation regarding inadequate LLRT procedures was identified. The

corrective measures to address the problems were acceptable.

M1.4 C&Dlainment Air Lock Reoairs and Testino

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a iticection Scoce (62707)

The inspectors observed the repr end postmaintenance test of the 113-foot elevation

(lower) primarj containment air ' ,k outer door equalizing valves.

b. Qbiervations and Findincs

Backgrouno: On October 30,1997, the licenseo performed the iower containment air

lock overall leakage test pursuant to TS Surveillance Requirement (SR) 3.6.1.2.1 and in

accordance with the licensee's primary containment leakage rate testing program. The

results were unsatisfactory to the extent that the leakage exceeded the acceptance

criteria and the capacity of the leak rate monitor (LRM). The control room operators wera

notified of the test failure and were also informed that the equalizer valves in the outer

door were leaking. The OSS declared the outer door inoperable and entered

TS ACTION 3.6.1.2.A, which required the operable (inner) door to be verified closed

in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and locked within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Failure to Enter Appropriate TS ACTION Statement: The inspectors identified that the

OSS had entered tha wrong T3 ACTION Statem.nt. Specifically, TS SR 3.0.1 states,

" failure to meet c Surveillance, whether such failure is experienced during the

performance of the SurveiMance or between performances of the Surveillance, shall La

failure to meet the LCO . " In this case, the surveillance for the entire air lock had failed

(not just the door) Therefore, the licensee was required to declare the LCO associated

with the air lock not met, which required entry into TS ACTION 3.6.1.2.C. Although the

inspector acknowledged that at least one known leak through one door was identi'ied, the

licensee had not demonstrated that no other leaks were present. The licensee agreed ,

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with the inspectors' assessment and entered the appropriate ACTION Statement.

Failure to Complete All Required TS ACTIONS: During subsequent reviews, thd

inspectors identified that after the licensee entered ACTION Statement 3.6.1.2.c, they

failed to comply with TS ACTION 3.6.1.2.C.1, which required the licensee to immerh tely

initiate action to evaluate primary containment overallieakage rate per TS LCO 3.6.1.1,

using current air lock test results. Although the OSS called engineering to inquire about

such an evaluation, no efforts were made to quantify leakage so that the evaluation could

be performed. The faiiure to implement all of the actions required by TS LCO 3.6.1.2.C

was a violation of TSs (VIO 50-458/9717 C4).

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Melntenance: Later on October 30, the inspectors observed mechanical maintenance

personnel replacing the inte.rnals on the outer door equalizing ball valves in accordance

with Frocedure MAI 314541. The inst.ectors examined the old balls and seats removed

from the valves and noted heavy scoring from dust and grit, which explained the leakage.

Postmaintenance Testing: The inspectors observed the postmaintenance test for the

repair work, conducted in accordance with Surveillance Test Procedure STP-057-3704,

" Primary Containment Air Locks Overall Leakage Rate Test," Revision 9, Section 7.1.5.

This section of the procedure leak tested the air lock door equalizer valves.

The inspectors ider.lified that the LRM bypass manifold w&s not vented in accordance

with Procedure STP-057-3704, Attachment 17. The bypass manifold was installed to

expedite pressurization of the overail air lock volume but was required to be isolated and

vented during the LLRT to ensure that potentialleakage past the manifold isolation valves

would not affect the test in a nonconservative manner. The inspector noted that the

bypass manifold was isolated but not vented. In response to the inspectors' concern, the

maintenance mechanics vented the bypass manifold. The inspectors had intervened

prior to the taking of test data, so valid test results were assured.

This was tho second time over a 2 month period where the LRM Lypass was not

appropriately vented dur9 leak rate testing. NRC Inspection Report 50-458/97-14

discussed a similar prob, where an LRM bypass manifold did not have a vent. The

establishment of the bypass manifold vent was considered skill of the craft, so no

procedural instructions were provided at that time, in the instance identified in the current

report, mechanics had adequate instructions but failed to vent the manifold properly.

Deferral of Surveillance: The inspectors identified that mechanical maintenance

personnel inappropriately deferred the overall air lock bak rate test until after startup ,

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without first considering possible use or maintenance that could have affected air lock

operability. Technical Requiremants Manual TSR 3.6.1.2.1.b requires the overall air lock

leak rate test to be performed every 30-months and " . prior to entry into Modes 2 or 3

from Mode 4 when the air lock has been used or maintenance has been performed that

could affect air lock sealing capability." The licensee had originally scheduled this

surveillance to be performed during Refueling Outage 7, which ended on October 21.

Mechanical maintenance personnel deferrsd the test after startup based on the frequency

requiren ent alone and failed to consider uss or maintenance that could have affected

operability,

l.1 response to the inspectors' concern, the licensee reviewed the use and maintenance

history for the air lock and determined that deferral of the surveiliance would have been

acceptable. Nonetheless, the licenses acknowledged that the personnelin question did

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not have an appropriate understanding of requirements prior to deferring the airlock leak

rate test. Additionally, the responsibility for the surveillance was recently transferred from

enginesing to maint3 nance and personnel involved had not effectively managed this I

change in ownership.

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c. Conclusiom

Subsequern to the failure of a containment air lock overall leak rate test, the OSS entered

the wrong TS ACTION Statement. The OSS an.ered the ACTION Statement for an

inoperable air lock door when he should have entered the ACTION Statement for an

inoperable air lock.

After the appropriate ACTION Statement was entered for an inoperable air lock, operators

failed to initiate action to ensure that the overall containment leakage rcte (usina air lock

test results) did not exceed that permitted by TSs. The failure to initiate this action was a

violation of TS 3.6.1.2.C.1.

Mechanical maintenance personnel inappropriately deferred the overall air lock leak rate

test until after startup without first considering possible use or maintenance that could

have affected air lock operability. This was an example of poor change managemen' as

this responsibility was mcently transferred from engineering to maintenance.

Maintenance technicians failed to vent the LRM bypass manifolds during local leak rate

testing. This is the second time in the past 2-months that a LRM bypass manifold venting

problem was identified (Section M1.2).

M1.5 HPCS Inservice Testing: During the performance of Procedure STP 203-6305,"HPCS

Quarterly Pump and Valve Operability Test," Revision 6, the HPCS Minimum Flow Valve

E22-MOV F012 unexpectedly closed when the suction was swapped from the

suppression pool to the ccodensate storage tank. Additionally, later in the curvel!!ance,

the valve failed to open when the test return valve was closed (dead heading de HPCS

pump). In response to the anomalous operation of the minimum flow valve, orierators

declared HPCS inoperable and entered the appropriate TS ACTION Stater v

While troubleshooting, maintenance personnel found air in the instrument lines to Flow

Transmitter E22-FAN-056. Engineering determined that air in the lines caused the

malfunction of the valve but had not determined the cause of the air intrusion into the

instrument lines by the close of the inspection period. The inspectors reviewed the

maintenance history for the flow transmi ter and noted that it was replaced in May 1997.

Just prior to that work, the minimum flow valve had failed to open during testing. This is

considered an unresolved item pending further NRC review of the licensee's root cause

evaluation (URI 50-458/9717-05).

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M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Review of Material Condition Durino Plant Tours

a. Inspechon Scoce (62707)

During this inspection period, the inspectors conducted routine plant tours to evaluate

plant material condition.

b. Observations and FindD23

• Drywell Insulation: During a prestartup walkdown of tne drywell, the inspectors

noted that some of the metalinsulation covers were in poor material condition. In

some cases, the cover fasteners were missing while in other cases the covers

were badly deformed. The material condition of the insulation covers v;as a

concem because, during a loss of coolant accident, the covers help to keep the

insulation in place and out of the suppression pool. The inspectors discussed this

observation with plant engineering and was informed that some of the feedwater

and main steam piping insulating material (including covers) was replaced during

Refueling Outage 7 and additional work was planned for future outages. The

inspecters considered the licensee's planned corrective measures to be

acceptable.

- CRD Pump 14: CRD Pump 1 A was experiencing higher than normal vibration,

which was believed to be caused by a damaged coupling. The licensee

considered the pump degraded but operable and maintained the pump in a

standby status. The pump may be utili' zed during emergency operating procedure

implementation for manual control rod movement and as a backup source of

primary coolant.

• Main Generator tiydrogen Leakage: Main generator hydrogen leakage was

approximately four times normal. The identified leakage pathway was through the

collector end generator seal ad out the roof vent (the normal hydrogen vent for

the system). A worsening of this condition could require a plant shutdown to

support repairs. The licensee planned to replace the seal during the next outage.

+ Postaccident Sampling Sgtem (PASS): The PASS was found inoperable on

November 12,1997, when two system fuseu view during a surveillance. Repairs

on the system were not complete at the close of the inspection period.

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Spent Fuel Pool Cooling (SFC) Pump 18: SFC Pump 1B was repaired recently

(new impeller) but during testing a sealleak was found. The pump remained in a

degraded condition until replacement parts could be ordered and installed. This

pump remained inoperable, but available, pending completion of the repairs.

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- ADHR, SPC Mode: The SPC mode of ADHR was rendered inoperable when an

NEO inappropriately operated the system and damaged a backwash valve. The

loss of SPC was of concern because suspended material and biological growth

from the suppression poc! has caused significant fauling in the RHR heat

exchangers.

c. Conclumond

Plant material condition was generally acceptable. The inspectors noted material

condition concerns with drywellinsulation, the SPC mode of ADHR, the PASS, main

generator hydrogen leakage, SFC Pump 1B, and CRD Pump 18.

M8 Miscellaneous Maintenance issues (92700)

M8.1 (Closed) Licensee Event Reoort (LER) 50-458/97-009: " . . inadequate pressure test

performances due to pressurizing through check valves." The issues contained in this

LER are discussed in Section M1.3 of this report. This LER is cbsed based on those

inspection efforts.

MS.2 Maane-Blast Breaker Refurbishment: The insp6ctor noted that three of the five

4160 Volt breakers in the HPCS switchgear had not been refurbished since initial plant

startup and had been in service approximately 13 years. This practice was inconsistent

with guidance from the Electrical Power Research Institute, whicn indicated that the

breakers should be refurbished, at most every 12 years. The licensee had planned to

refurbish the three subject breakers over the next 9 to 12 months.

lit f.ngine.edag

E2 Engineering Support of Facliities and Equipment

E2.1 EHR A Line Break Alarm Failed to Clear Durina and After Startuo

a. Insoection Scoce (37551,

The inspectors reviewed the engineering resolution of CR 97-1915, which identified the

control room annunciation of a " Division I RHR system ' . operative alarm" coincident with

an *RHR A line break" status light.

b. Observations and Findinas

On October 25,1997, while operating the plant for the first time in accordance with

MELLA conditions, the control room alarm for " Division l RHR system inoperative"

annunciated coincident with the "RHR A line break detected" status light. This alarm was

unexpected and was provided to inform operators of a potential RHR A or low pressure

core spray line break. Operators verified that line break conditions did not ex.st, but the

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alarm remained sealed in for several days. Eventually, with power stable at 100 peicent >

and core flow at 88 percent, the alarm cleared.

Engineering evaluated the annunciator problem and determined that the change in steam

quality in the reactor vessel (caused by the recen~'y initiated MELLA operating conditions)

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affected the density of water ;.1 the subject instrument lines sufficiently to bring in the

alarm. The licensee noted that, historicalh', during plant startups (at less than

100 percent power), the alarm normally comes in for similar reasons. The alarm setpoint

is consistent with the steaoy state full power / full flow conditions (but not MELLA

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conditions). The inspectors consulted vith experts in the Office of Nuclear Reactor

Regulation and determined that the licensee's conclusions were credible and well

supported.

At the close of the inspection period, the licensee had not developed the corrective

actions necessary to ensure that the subject annunciators would continue to provide

meaningful indications under both MELLA and non-MELLA operating conditions.

However, the licensee did not expect further false indications from the annunciators for

the remainder of the operating cycle.

c. Conclusions

The inspectors concluded that the engineering disposition of the RHR line break

annunciation under MELLA conditions was acceptable.

IV. Plant Suonort

R1 Radiological Prostion and Chemistry Controls

R1.1 Radiological Controls Associated with the Traversing incore Probe (TIP) System

a. Insoection Scooe (71750)

The inspectors reviewed compliance with radiological controls associated with the TIP

system,

b. Observations and Findings

Upon exiting the drywell on October 17,1997, the inspectors observed that the TIP i

system was secured but was not danger tagged. The inspectors questioned the lack of

danger tags because Procedure RSP-0212 "Drywell Entry," states, "The Traversing

incore Probe Drive System should be tagged out with the TIPS stored in the Lower

Plenum or in the Reactor Vessel for all entries into the dn/well." The radiation protection

personnel were responsible for proper implementation of Procedure RSP-0212.

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Additionally, the procedural recommendation was annotated as being responsive to

concerns identified in NRC Information Notice (lN) 88-63, "High Radiation Hazards from

Irradiated incore Detectors and Cables." NRC IN 88-63 discussed severalinstances

where inadequate TIP system controls resulted in several over-exposure events at other

facilities.

The licensee agreed with the inspectors observation and determined that health physics

personnel had mistakenly come to believe that this management expectation only applied

to initial drywell entries, in response to the finding, the licensee briefed appropriate health

physics personne' regarding the appropriate interpretation of Procedure RSP-0212. The

licensee further stated, however, that tagging the TIPS out of service for all drywell entries

was overly restrictive and that the controls would be revised. The issues discussed in

NRC IN 88-63 would be properly considered when the new contrals were developed.

c. Conclusions

The inspectors identified that health physics personnel did not meet management

expectations with regard to ensuring that the TIP system was danger tagged off when

drywell entries were made.

V. Management Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on December 1,1997. The licensee acknowledged the findings

presentad.

The inspectors asked the licensee w' n'her any materials examined during the inspection should

be considered proprietary. No prnpr etary information was identified.

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AIJACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensen

J. P. Dimmette, General Manage, Plant Operations

M. A. Dietrich, Director, Quality Programs

D. T. Dormedy, Manager, Svstem Engineering

T. O. Hildebrandt, Manager, Maintenance

J. Holmes, Superirtendent, Chemistry

H B. Hutenens, Sgerintendent, Plant Security

D. N. Lorfing, Supervisor, Licensing .

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J. R. McGaha, Vice President Operations

M. G. McHugh, Licensing Engineer lil

W. P. O'Malley, Manager, Operations

D. L. Pace, Director, Design Engineering

A. D. Wells, Superintendent, Radiation Control

INSPECTION PROCEDURES USED

IP 37551: Onsite Engiaeering

IP G1726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 71750: Plant Support

P 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

Facilities

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s lTEMS OPENED AND CLOSED : - --

QNtoed

50 4 58/9717-01- NCV : Failure to Follow ECCS Test Procedure

50-458/9717-02 URI -- Uneyected Isolation of ADHR Valves

50-458/9717-03 .NCV inadequate LLRT Prxedures:

.50-458/9717-04-

VIO Failure to Comply with TS ACTION 3.6.1.2.C.1 after Air Lock -

Surveillance Failure

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[50-458/9717-05- URI -Air in HPCS Instrument Line Causes SuNeillance Failure

Closed

-50-458/9717 01 'NCV Failure to Follow ECCS Test Procedure

50-458/9717-03 -NCV Inadequate LLRT Procedures

'50-458/97-009: LER Inadequate Pressure Test Performances due to Pressurizing

_

Through Chack Valvas

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LIST OF ACRONYMS USED

ADHR alternate decay heat removal

CR condition report

CRD: control rod drive

differential pressure

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ECCS- emergency core cooling system

-HPCS high pressure core spray i

IN - - Information Notice --

,LCO- limited conditio_n of operation

4 LER --  : licensee event report.

LLRT' localleak rate test

LRM: <

leak rate monitor

- MELLA L maximum extended load line allowance

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sNCV' Noncited violation ~

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NEO" Nuclear Equipment Operator :

U.S Nuclear Regulatory Commission

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3. - operations shift superintendent 4

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postaccident sampling system

1RCIC f reactor _ core isolatwn cooling 4

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-RHR -

residual heat ramoval

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RWCU reactor water cleanup

SFC spent fuel cooling

SPC suppression pool cleanup

SR surveillance requirement

TIP traversing in-core probe

TS Technical Specifications

URI unresolved item

RBS River Bend Station

VIO violation

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