ML17333A910

Forwards Response to Violations Noted in Insp Repts 50-315/97-04 & 50-316/97-04.Corrective actions:post-trip Recovery Procedures Will Be Revised Re Placement of TDAFP in Standby Readiness

ML17333A910
Person / Time
Site:	Cook
Issue date:	06/05/1997
From:	FITZPATRICK E AMERICAN ELECTRIC POWER CO., INC.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
50-315-97-04, 50-315-97-4, 50-316-97-04, 50-316-97-4, AEP:NRC:1260C, NUDOCS 9706090357
Download: ML17333A910 (40)

See also: IR 05000315/1997004

Text

Indiana Michigan Power Company 500 Circle Drive Buchanan, Ml 491071395 INblANA MICHIGAN POWER June 5, 1997 Docket Nos.: 50-315 50-316 U.S.Nuclear Regulatory

Commission

ATTN: Document Control Desk Washington,-D.-C.

-20555 Gentlemen:

AEP:NRC:1260C

10 CFR 2.201 Donald C.Cook Nuclear Plant Units 1 and 2 NRC ZNSPECTZON

REPORTS NO.50-315/97004 (DRP)AND 50-316/97004 (DRP)REPLY TO NOTZCE OF VZOLATZON This letter is in response to a letter from J.L.Caldwell, dated May 6, 1997, that transmitted

a notice of violation and a notice of deviation to Indiana Michigan Power Company.The notice of violation contained a total of eight violations

of NRC requirements

identified

during an NRC inspection

conducted from February 16, 1997, through March 29, 1997.The violations

pertain to procedures, corrective

actions, reportability

requirements, and 10 CFR 50.59.issues.Our response to these violations

is provided in attachment

1.The notice of deviation involves inoperability

of control room power range pen recorders.

Our response to this item is provided in attachment

2.EE+pW E.E.Fitzpatrick

'1ice President SWORN TO AND SUBSCRZBED

BEFORE ME~=-" TEZS.~g DAY OF 1997 Notary Public vlb UNDA L BOIlCKE Norory Public, Berrlen Coonly, Ml Attachments

My Commr&on Iorpires jonoory 21, 200I 9'706090357

970605 PDR ADOGK 050003i5

1ndiana Michigan Power Company 500 Circle Drive Bvchanan, Ml 491071395 INDIANA NICHIGAH POWER May 5, 1997 Docket Nos.: 56-315 50-316 U.S.Nuclear Regulatory

Commission

ATTN: 33ocument Control Desk-Washington,--D.--C;-20555

Gentlemen:

AEP:NRC:3.260C

3.0 CFR 2.201 Donald C.Cook Nuclear Plant Units 1 and 2 NRC INSPECTION

REPORTS--NO.

50.-3/5/97004

-(DRP)AND 50"316/97004 (DRP)REPLY TO NOTICE.OF VIOLATION This letter is in'response

to a letter from J.L.Caldwell, dated May 6, 1997, that transmitted

a notice of violation and a notice of deviation to 1ndiana Michigan Power Company.The notice of violation contained a total of eight violations

of NRC requirements

identified

during an NRC inspection

conducted from February 16, 1997, through March 29, 1997.The violations

pertain to procedures, corrective

actions, reportability

requirements, and 10 CFR 50.59 issues.Our response to these violations

is provided in attachment

1.The notice of deviation involves inoperability

of control room power range pen recorders.

Our response to this item is provided in attachment

2.E.E.Fitzpatrick

'1ice President SWORN TO AND SUBSCRIBED

BEFORE ME THIS DAY OF 3.997 Notary Public vlb UNDA l SOEt,CKE No&y Pubhc, Bergson Cooniy, Ml Attachmentsg

QyCpzmi+~~fQ$

PDR ADQCK 050003i5 8',, PDR;, n'j>QQ5 Illlmllll!

Iillllllllllljlll(lllllll

U.S.Nuclear Regulatory

Commission

Page 2 AEP: NRC: 1260C c: A.A;Blind A.B.Beach MDEQ-DW&RPD NRC Resident Inspector J.R.Padgett~~l><l

ATTACHMENT

1 TO AEP:NRC:1260C

RESPONSE TO NOTICE OF VIOLATIONS

~~

Attachment

1 to AEP:NRC:1260C

Page 1 During an NRC inspection

conducted from February 17, 1997, to March 29, 1997, four violations

of NRC requirements

'ere identified.

In accordance

with the'."General

Statement of Policy and Procedure for NRC Enforcement

Actions", NUREG-1600, the violations

are listed below.NRC Violation 1a"10 CFR 50 Appendix B, Criteria V, Inspections, Procedures, and Drawings, requires in part, that activities

affecting quality shall be prescribed

by procedures

of a'type appropriate

to the circumstances

and shall be accomplished

in accordance

with these---=---=--procedures;--

Contrary to-the above, The inspectors

identified

that Procedure 02-OHP 4023.ES-01"Reactor Trip.Response", revision 11, dated 11/21/96, was not appropriate

to the circumstances

because it did not contain guidance for adequately

controlling

steam generator (SG)levels while actions were being taken to minimize the reactor coolant system cooldown rate.As a result, on March 11, 1997, a Unit operator reset a turbine driven auxiliary feed pump (TDAFP)too close to the low-low SG level setpoint which resulted in an inadvertent

Engineering

Safeguard Feature actuation.

This is a Severity Level IV violation (Supplement

I)." Res onse to Violation 1a 1.dmission or Denial of the Alle ed Violation Indiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

2.Reason for Violation This violation resulted from incomplete

guidance in procedure 02-OHP 4023.ES-O.l,"Reactor Tri'p or Safety Injection", that allowed the restoration

of the TDAFP prior to the unit being in a stable condition.

During the performance

of 02-OHP 4023.ES-0.1, the control room team is allowed to remove the TDAFP from service if sufficient

feedwater is being supplied to the SGs from the two motor driven auxiliary feedpumps.

This flexibility

to remove the TDAFP from service provides the operators with additional

reactor coolant system (RCS)temperature

control.Technical specifications (T/Ss)3.7.1.2 and 3.3.2.1 require the TDAFP be operable and capable of automatically

starting in mode 3.To comply with these requirements, ES-0..1 directs the TDAFP governor to be reset and the valve alignment to meet the standby readiness requirements.

The auto start function is enabled af ter all standing automatic start signals have cleared.During the post-trip scenario the standing automatic start signals are the low-low SG level on.two ef.four SGs,~and,the.mticipated.t

ransient without" scram mitigatien'ystem

actuation circuitry (AMSAC)signal.The

Attachment

1 to AEP:NRC:1260C

Page 2 3~AMSAC signal occurs after all high power trips and is only required above 40%power.The AMSAC signal is then cleared manually during the performance

of ES-0.1.The SG low-low level actuation signals are cleared by recovery of SG levels, utilizing the AFW pumps.During the post trip recovery on March 11,'997, the AMSAC signal was reset prior to the complete recovery of all SG levels to above the low-low automatic actuation setpoint.The¹21 SG level lagged the others, as, the loss of main feedwater to that SG was the initiating

event which resulted in the reactor trip, and continuous

feeding of.the SGs was in progress-to-recover=secondary

side inventory levels.While filling the SGs, small.oscillations

normally occur in the sensed level.With the¹21 SG level still below the low-low setpoint,,a.small oscillation

occurred in¹23 SG that caused the TDAFP auto start signal to clear at its high point, followed by.the engineered

safety feature (ESF)actuation when it subsequently

dropped and went below the ESF setpoint.Because the setpoint has a 1%reset deadband, it is'extremely

sensitive to minor oscillations.

Due to the incomplete

guidance provided..:in

the emergency.procedure,-emphasis was placed on the restoration

of.the TDAFP to standby readiness, rather than on stabilizing

SG levels above the ESF actuation setpoint prior to securing the TDAFP and placing it in standby readiness.

Corrective

Action Taken and Results Achieved 4~The TDAFP started as designed and performed its desired function.Manual control of th'e SG levels during the post trip recovery continued.

No immediate corrective

actions were required.Corrective

Actions to Avoid Further Uiolations

The post-trip recovery procedures

will be revised regarding placement of the TDAFP in standby readiness.

These revisions will allow operators flexibility

in equipment management

during post trip responses, so that the operator may focus attention on the plant response as post-trip stabilization

occurs, while continuing

to meet the requirements

of the T/Ss for auxiliary feedwater and ESF actuations.

An engineering

review of the SG low-low level instrument

deadband is being performed.

The purpose of the review is to determine the appropriateness

of the 1\reset deadband.This review will be completed prior to the next scheduled calibration

surveillance

of the associated

instruments.

5.Date When Full Co liance Will Be Achieved Full compliance

will be achieved by September 1,, 1997, with.the completion

of the engineering

review of the reset deadband, and the revision of the appropriate

post trip recovery procedures.

F we'll 4 d

Attachment

1 to AEP:NRC:1260C

Page 3 NRC Violati.on

1b"On March 23, 1997, the inspectors

identified

that the licensee failed to follow, instructions

when personnel woxking adjacent to the refueling cavity in a foreign material exclusion zone, failed to secure light hand tools to themselves

by way of a lanyard or tagline, and failed to restrain tools in, the FMEZ when they set the'ools down.These actions were required by Plant Manager's Instruction (PMI)2220,"Foreign Material Exclusion", revision 9, dated 3/26/96.This is a Severity Level IV violation (Supplement

I)." Res onse to NRC Violation 1b 1~A Admission-or

'Denial of the Alle ed Violation Indiana Michigan Power Company, admits to the violation as ci.ted in the NRC notice of violation.

2.Reason for the Violation 3.Contract technicians, under I&M supervision, were, making repairs to a dual view camera fixture in a foreign material exclusion zone (FNEZ)when they were observed using hand tools with lanyarda attached to the.tools, but not secured to a person or fixed object.This condition resulted from a misi.nterpretation

of the requirements

of plant procedure 12 PMP 2220.001.001,"Foreign Material Exclusion" (FNE).Section 5.2.7 of this procedure states, in part,"Light hand tools shall be secured'to

the person using them by way of a lanyard or tagline.".However, fuxther on in the same procedure under a section entitled"Securing Tools" (attachment

2, part 6a)it is stated"Tools or equipment which could fall into openings beyond the reach of personnel MUST be secured with a lanyard or tag line, where practical."'he lanyards were felt to be.impractical

by the workers~involved in the job.Because attachment

2 did not require lanyards where impractical, the workers did not use them.Additionally, these same contract technicians

were observed leaving tools lying loose within an FMEZ.The~persons involved had incorrectly

assumed that the"intent" of the FNE procedure was being followed by the compensatory

actions they had taken prior to beginning the equipment repair.These actions included: 1)establishing

a laydown area within the FMEZ for the specific purpose of repairing this equipment;

and 2)assigning an individual

to specifi.cally

monitor and control loose parts and tools during the repair evolution.

Similar FME practicea had been employed at other nuclear sites.However, the Cook Nuclear Plant procedure that governs activities

within an FNEZ (12 PMP 2220~001.001)specif ically mandates the use of lanyards, and does not-.recognize other methods of material control.Corx'ective

Actions Taken and Results Achieved Upon notification

of the NRC inspectors'oncerns, the project management

a installation

services (PMRIS)production

supervisor

contacted.

the contractor's

site coordinator,-who reins tructed the te'chnicians

on Cook Nuclear Plant FNE

Attachment

1 to AEP:NRC:1260C

Page 4 4, requirements.

No additional

problems relating to hand tool usage were recorded during the remainder of the project.Corrective

Actions To Avoid Further Violations

Proce'dure

12 PMP 2220.001 will be revised prior to the fall 1997 unit 2 outage.This revision wilI eliminate th" d screpancies

noted within the procedure, and provide the i e" flexibility

for using other methods of material control.On May 27, 1997, a plant-wide'-

>>time-out" was held to highlight management'.s

expectations

in the area of procedure c mpliance.-During this-period, plant and contract employees (including

supervision)

were brought together to focus on the usage of plant procedures.

PMZ-2011,"Procedure

'se and Adherence", was reviewed.Emphasized

topics included the various.levels of procedure usage (continuous

use, information

'use, referende use)and the company policy of strict procedural

compliance.

Additionally, PM&IS will hold another procedural

compliance

>>time-out" prior to the fall 1997 unit 2 outage.Procedural

adherence issues will be re-emphasized

to both ZaM and contract personnel (including

supervision), as well as to individuals

brought in specifically

for outage support.Within thirty days of the end of the outage, PM&IS will also perform a self-assessment

in the area of procedure adherence to determine the effectiveness

of our procedural

compliance

efforts.Date When Full Com liance Will Be.Achieved Full compliance

was achieved on March 23, 1997, after all p ysical work had been stopped and the workers'were reschooled

on'Cook Nuclear Plant FME requirements (PMZ-2220)

and our policy regarding strict procedural

compliance.

NRC Violations

1c and 1d"On March 11, 1997, the licensee identified

that during refurbishment

of 1-QRV-114, the reactor coolant'xcess letdown to excess letdown heat exchanger shutoff valve, in 1994, the valve was reassembled

without a cage spacer that was required by maintenance

procedure 12 MHP-5021.001.057,"Copes-Vulcan

Isolation Valve Maintenance>>'evision

1, dated 3/14/97'his is a Severity Level IV violation (Supplement

I).1d.On March 16, 1997, the licensee identified

that during the 1995 refurbishment

of 1-NRV-163, the pressurizer

spray control valve, the valve was reassembled

without a cage spacer that was required by maintenance

procedure 12 MHP-5021.001;126,"Copes-Vulcan

Bellows Seal Control Valve Maintenance", revision 1, dated 3/13/97.This is a Severity Level IV violation (Supplement

I)."

Attachment

1 to AEP:NRC:126QC

Page 5 Res onse to C Violation 1c and Zd Admission or Denial of the Viol'ations

Indiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

Reasons for the Violation This violation was caused by standards and expectations

for contract valve technician

performance

of work to an in-hand procedure being too low.Proper implementation

of, the-procedures-by-the-technicians

was not verified and reinforced

by the first line supervisors.

An additional

factor included the valve technician's

lack of familiarity

with the specific configuration

of this style of valve.'U Normal maintenance

'ractice for Copes-Vulcan

valve disassembly

is to remove the bonnet with the stem intact.This also includes removal of the plug, cage assembly, and cage spacer.During a normal refurbishment

the plug and cage assembly are replaced.In these cases, the easiest way to disassemble

the internal parts is to cut the stem and let the plug and cage assembly fall into a radwaste container.

This usually means that the cage spacer also falls into the waste container.

The replacement

cage, disc, and stem are normally provided together as a"trim assembly".

Because the cage spacer does not see the wear that the plug and cage assembly see, it does not normaLLy need to be replaced during a refurbishment.

Therefore, th'e cage spacer is not included with these parts in a trim assembly.The existing cage spacer must generaLLy be reused when.the valve is reassembled.

Copes Vulcan valves have a unique cage.spacer

configuration, which the technicians

~did not commonly work with.Nonetheless, the procedure does specifically

call for reinstallation

of the cage spacer as part of reassembly

of the valve internals.

3.Corrective

Action Taken and Results Achieved 4~1-QRV-114 was properly reassembled, with new internals, under JOA R36179-02.

This was completed on March 18, 1997.1-NRV-163 was propeily reassembled, with new internals, under JOA C34692-02.

This was completed on March 27, 1997.Corrective

Actions Taken to Avoid Further Violations

Two Copes-Vulcan

valves have been purchased for training purposes.One valve is configured

as a"typical" Copes-Vulcan control valve.The other valve is a duplicate configuration

of the pressurizer

spray valves.Designation

of the cage spacer will be in bold in the reassembly

step in Maintenance

procedures

for Copes-Vulcan

valves.A review'f.the maintenance'procedures

for Copes-Vulcan

valves will be conducted.

Emphasis wilL be on consolidation

Attachment

1 to AEP:NRC:1260C

Page 6 5.of the piocedures

and implementation

of engineering, plannihg, or supervisory

identification

of applicable

procedure information

based on the internal conf iguration and application

of the valve.This.will be completed b September 1, 1997.e e y Maintenance

personnel have been reminded of the need to'roperly

implement in-hand procedures.

This means they must read the step, perform the step, document completion

of the step, then proceed to the next step.At the time of the original valve work in 1994, contract supervisors..performed-

hands-on work=as well's serving as supervisors.

Since 1994, this has been changed and contract supervisors

no longer perform hands-on work, but function re l solely in an oversight role.This is reinforced

thr h oug 8 gu ar meetings held during the outage.The contr ct n rac bri upervisors

are now more involved in preparation

and p-'re-jo er'efings, and general expectations

for contract p formance, especially

regarding procedural

adherence,,is

or discussed.

with contract management

prior to the start of the outage.Date when Full Com liance will be Achieved Full compliance

was achieved on March 27, 1997.At that time, both valves were properly reassembled.

NRC Violation 2a"10 CFR 50 Appendix B, Criteria XVZ, Corrective

Actions, requires in part, that"Measures shall be established

to assur that Zn the case of signifidant

conditions

adverse to qu 1't th (cor (rective)measures shall assure that the cause of the condition is determined

and corrective

action taken to preclude repetition." II Contrary to the above, a.On March 11, 1997, in Unit 2, the previous corrective

actions to preclude the buildup of electrostatic

discharge.from affecting Taylor Mod 30 controllers

were ineffective

in preventing

the failure of the controller

for feedwater regulating

valve 1-FRV-210.

This controller

failure caused the closure of 1-FRV-210 and a subsequent

reactor trip." This is a Severity Level ZV.violation (Supplement

Z)." Res onse to NRC Violation 2a Admission or Denial of the Alle ed Violation Zndiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

Reason for the Violation The cause of this violation'is an inadequate

root cause determination

for the previous controller.

failures ca The iroot cause determin'ation

had'identified

the static electricity

but

Attachment

1 to AEP:NRC:1260C

Page 7~0 3.failed.to identify the severity of the problem.Steps had been implemented

to reduce the occurrence

of static electricity.'owever, not.all", processes that could cause static were identified.

Although measures had been taken to reduce static buildup and to provide a means to safely discharge the static, some day-'o-day

practices that could generate static were not identified, nor was it identified

that the methods provided to discharge the static were not always effective.

Zt had been verified that the carpet installed in-the control rooms was a static dissipative

carpet, humidity levels in the control~corns

-were being maintained

above 40%, and electrostatic

discharge (ESD)mats had-been.placed in front of the control panels.However, after the unit trip, it was discovered

the controls of the steam generator'level ,controllers

were located at a convenient

height to make it common practice.for operators to roll.over to the controllers

in'-wheeled office chair and adjust the controls.This rendered the static dissipative

carpet and ESD mats installed in front of the control panel ineffective

at dissipating

static electricity.'ngineering

had also instructed

the operators to discharge their static charge on the control panel prior to.contacting

controllers

but failed to note the painted surfaces on the control panel-did not provide for proper grounding;

Additional

grounding methods for the controllers

had been developed to reduce the vulnerability

of, the controllers

to failure during ESD.An'implementation

schedule was developed, based on the need to remove a controller

from service to perform grounding.

Because of this, a number of controllers

could not be done with the unit operating.

This was judged to be acceptable

in view of the actions taken to reduce static buildup and providing a means to di.scharge

the static prior to an operator interfacing

with the controller.

The controller

that failed and caused the March 11, 1997, unit trip was scheduled for the grounding enhancement

during the next refueling outage.Corrective

Ste s Taken and Results Achieved The enhanced grounding methods were installed in unit 2 during the forced, outage from the'ontroller

failure and on unit 1 during the refueling outage.Additional

in-house testing of the controller

confirmed the manufacturer's

identification

of ESD sensitivity

at the right edge of the faceplate.

Testing also showed that sealing the edge of the faceplate prevented static intrusion and doubled the immunity to static discharge.

All panel mounted controller

faceplates

for both uni.ts were sealed to prevent static intrusion.

Additional'SD

readings were taken in the control rooms while operators were performing

routine activities, to more thoroughly

quantify the static problem.Testing showed an operator could generate 3KV with a simple act of standing up from a chair.Static electricity

also failed to,immediately

~drain,while standing;on:>, the anti-static-.-carp'et;-'.and

'took-several=seconds to.drain while standing on the ESD grounding

0

Attachment

1 to AEP:NRC:1260C

Page 8 mats due to the insulated shoes worn by most operators.

Following testing, ESD-proof chairs were installed in the control room and operators were'.required to wear commercial

shoe grounding straps.Follow-up checks indicated that while operators are wearing the grounding strap, static charge buildup would dissipate immediately

on contact with the ESD mats and there was no charge buildup while using the ESD'hair.As a point of information, a design change is being finalized to incorporate

a.failover control system design to prevent single point controller

failure in critical instrument, loops from=shutting-down-the

control loop.Failed controllers

will be bypassed with-operator notification

and, depending on which controller

failed, continue in auto or revert to manual for operator control.4.Corrective

Actions To Avoid Further Violations

The cause of this violation was failure to properly identify and fully characterize

root causes of the failure.A review and revision of Cook Nuclear Plant PMI-7030,"Corrective

Action Program," was recently completed and additional

training of personnel in proper root cause analysis is being performed.

5.Date When Full Co liance Will Be Achieved Full compliance

was achieved on May 9, 1997, with the completion

of the grounding modifications

during the unit 2 forced outage, and on unit 1 during the refueling outage.PMI-7030, revision 23,"Corrective

Action Program", was effective May 19, 1997, and personnel training is ongoing.NRC Violation 2b"10 CFR 50 Appendix B, Criteria XVI, Corrective

Actions, requires in part, that"Measures shall be established

to assure that In the case of significant

conditions

adverse to quality, the (corrective)

measures shall assure that the cause of the condition is determined

and corrective

action taken to preclude repetition." Contrary to the above, On March 12, 1997, the inspectors

identified

that the corrective

actions following a repeat gasket failure on l-IRV-311, identified

on January 31, 1996, were inadequate

to preclude repetition

of spiral wound gasket material entering the reactor coolant system, a significant

condition'adverse to quality.Specifically, the licensee performed an evaluation

to-determine the ef fect of spiral wound gasket material in the residual heat removal system;however, no action was taken to remove this material which resulted in the.re-introduction

of spiral wound gasket material in the reactor coolant system on March 12, 1997." This is a Severity Level IV violation (Supplement

I)."

Attachment

1 to AEPsNRC:1260C

Page 9 onse to Vh.olation

2b Admission or Denial of the Alle ed Violation\Indiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

2.Reason for Violation This violation is the result of an inaccurate

root cause determination

for the initial failure of the gasket, which occurred in August 1995.The root cause determination

was not accurateMecause

=information--necessary"to make an accurate determination

was not available at the time of the initial investigation., A design.change previously

installed to improve residual heat removal (RHR).flow control replaced the.original butterfly valves with a V-notched ball valve, model V100-Sin-300lb, manufactured

by Fisher Controls.When this design change w l was engineered, it was not known that excessive turbulen ou d develop at the valve's downstream

flange when the valve was throttled to an intermediate

position.This turbulence

can result in hydraulic forces capable of damaging the metallic winding of the spiral wound gasket used to seal-this.bolted connection.

Subsequent

f ailures of the gasket.provided information

not available't

the time of the initial investigation.

This information

led us to the conclusion

that the valve and flange gasket are incompatible, and the incompatible

design resulted in the gasket failures.fl On August 11, 1995, the unit 1 RHR heat exchanger (Hx)bypas ow control valve, 1-IRV-311, downstream

flange gasket ass failed with RHR in service during normal cooldown at the end of cycle 14.When 1-IRV-311 was disassembled

for repair, it was discovered

that the inside diameter of its gasket was smaller than the inside diameter of the corresponding

slip-an flange.This.resulted in approximately

0.155 inches of the gasket's metallic spiral windings being exposed to the flow stream, and resulted in gasket failure.The root cause of the initial failure was therefore determined

to be an incorrectly

sized gasket.~Neither of the other two RHR Hx outlet flow control valves, 1-IRV-310 and 1-IRV-320, have this type of slip-on bolted.flange connection

or evidenced a flange leak.Therefore, they were not.inspected at this time.1-IRV-311 was returned to service with new spiral wound gaskets of the correct size.The emergency core cooling system (ECCS)and RHR were flushed of debris, and unit 1 began operation for fuel cycle 15.Shortly after the completion

of the unit 1 1995 refueling outage, with the ECCS and RHR.in standby readiness, leakage from the downstream

joint of 1-IRV-311 again occurred.When the valve.was removed for repair on January 31,.1996, its downstream

flange gasket was found to have experienced

damage similar to the previous failure, with a portion of the spiral windings missing.The root, cause of this failure was determined

to be incompatibility

of the spiral wound gasket with=the V-ball, type:of.control valve.A non>>metallic

fibrous gasket was installed in place of the spiral wound

Attachment

1 to AEP:NRC:126QC

Page 10 gasket.Once again, 1-IRV-310 and 1-IRV-320 were not opened because they were not exhibiting

any evidence of leakage, nor were they suspected of susceptibility

to this type of failure as their throttling

characteristics.

differ from 1-XRV-311.

As a precautionary

measure.in March of 1996, 2-XRV-311, the unit 2 RHR Hx bypass flow control valve, was'opened for had n inspection

prior to the unit 2 refueling outage.This al ot evidenced leakage at the downstream

joint;however, its spiral wound gasket was found to be damaged upon valve disassembly.

This provided.thefirst evidence that the flange gasket could become damaged without manif esting-.external

leakage;--.A-fibrous

gasket was installed in place of the spiral, wound gasket.During the refueling outage, the spiral wound gaskets were-removed" from,2-IRV-310

and 2-IRV-320 and replaced with fibrous gaskets.The spiral wound gaskets removed from 2-XRV-310 and 2-IRV-320 were intact, reinforcing, the conclusion

that the 1-IRV-310 and 1-IRV-320 were not at risk for this type of failure.During the recent unit 1 refueling outage, a visual inspection

of the reactor's lower core plate revealed more spiral wound gasket debris than would have been expected from the failure of 1-IRV-311 discovered

in January of 1996.Up to this point, all failures of-the spiral wound gasket were'believed to be isolated to the RHR Hx bypass flow control valve used in the normal cooldown circuit.Although 1-1'RV-310 and 1-IRU-320 had no evidence of leakage, they became suspect as another potential source of debris.When each valve was disassembled

for an internal inspection, their downstream

spiral wound gaskets were found partially unwound."'.On March 3, 1997, during the unit 1 RCS/ECCS as found pressure isolation valve (PIV)leak test, it was determined

that two PIV check valves had failed their leak test du e presence of gasket fragments.

This debris was subsequently

removed and an as-left leak test for all PIVS was performed in April 1997 to demonstrate

the class I pressure boundary was intact prior to the beginnin of cycle 16.ing o Corrective

Action Taken and Results Achieved 4.The spiral wound gaskets were removed from all RHR flow control valves in both units.Corresponding

bolted connections

are now sealed with fibrous gaskets which are not susceptible

to this form of erosion induced by localized turbulent flow.The RHR piping network branches.and ECCS branches in both units 1 and 2 have been flushed to remove foreign material debris, including gasket fragments.

Corrective

Actions To Avoid Purther Uiolations ,Xt was confirmed that no other incompatible

gasket design of this nature was installed in a system relied upon to achieve safe shutdown or mitigate the consequences

of an accident.

Attachment

1 to AEP:NRC:1260C

Page 11 5.'Date When Full Com liance Will Be Achieved Full'ompliance

was achieved on March 21, 1997, when the last spiral wound gaskets were replaced for 1-IRV-310 and 1-IRV-320.NRC Violation 3"10 CFR Part 50.72, paragraph (b)(2)(i), requires that any event, found while the reactor is shut down, that, had it been found while he reactor was in operation, would hav'e resulted in the nuclear power plant, including its principal safety barriers beings an analyzed-condition

that signi.fi.cantly

compromises

plant safety, be reported to the NRC within four hours of occurrence.

Contrary to the above, the licensee failed to make a timely report in accordance

with 10 CFR 50.72(b)(2)(i)when on March 21, 1997, inspection

of flood-up tubes in Unit 1 identified

cracks in nine tubes and the equipment associated

with these flood-up tubes was declared inoperable.

This is a Severity Level IV violation (Supplement

I)." Res onse to NRC Violation 3 Admission or Denial of the Violation Indiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

2.Reasons for the Violation The.primary reason for the violation was the low emphasis placed on resolution

of an indeterminate

reportability

condition.

Environmental

qualification (EQ)issues are complex.The personnel who made the initial reportability

decision when the degraded condition was identified

on unit 1 were unfamiliar

with EQ issues as they relate to system and component operability.

It was decided to submit the condition for further reportability

evaluation

via the process embedded in our corrective

action program.The resulting timetable did not appropriately

reflect NRC expectations

for promptly evaluating

and reporting degraded conditions.

The parallel work to inspect, evaluate, and repair tubes in the operating unit 2, took priority over further evaluation

of the unit 1 conditions.

This prioritization

of resources was appropriate

based on the safety significance

of the condition in the operating unit versus the shutdown unit;however, it extended an already unacceptable

delay in the reporting of the unit 1 condition.

A contributor

to the length of the delay in reporting was the completion

of the evaluation

to confirm all inoperable

equipment.'his

provided for determination

of the complete safety significance

prior to making a final reportability

determination.

Of the original nine cracked tubes, only seven resulted in declaring equipment inoperable.

Twenty-three devices were serviced by the conduit in the seven floodup tubes, and of these, only thirteen devices were.confirmed

to be inoperable.

~~oi Attachment

1 to AEP:NRC:1260C

Page 13 determination

that the change does not involve an unreviewed

safet question.we sa e y Contrary to the above, on March 6, 1997~, the licensee identified

that a plexiglass

cover was installed below the return air duct to the unit 2 control room without a proper 50'9 safety evaluation.

o e his plexiglass

cover had the potential of affect'n th'CREVS).p rability of the unit 2 control room emergency ventilation

t sys em This isa Severity Level IV violation (Supplement

I)." I Res onse..to-NRC

Violation--4'.

Admission or Denial of the'Alle ed Violation i yiqpsr Indiana Michigan Power Company admits to the violation as cited in the NRC notice of violation.

2.Reason for the Violation The cause of this violation's inadequate

procedural

guidance.Specifically, the procedure regarding the adminis trat'ion'f"Temporary

Modif ications",.1'2 PMP 5040.MOD.001,, revision..5, defined a temporary modification (TM)as follows: 3.Any configuration

change that exists on plant systems, components, or structures, (hereafter

referred to as equipment)

which does not conform to approved plant drawings, approved vendor drawings, or other design documents (i.e., ECPs, EDSs, PDSs)and is being used to maintain operation of the plant.A modification

on any equipment being returned to service, though not.being used in support of plant operations, where the modification

has the potential to adversely affect plant equipment or personriel

safety, shall be considered

a temporary modification.

At the time of the event, installation

of the drip catch basins on the panels near the control room emergency ventilation

system (CREVS)intake ducts was not considered

a TM per the procedure because it, was not to be installed on an operating system, and the, basins were not required to maintain operation of the plant.Corrective

Actions Taken and Results Achieved The drip catch basins were removed from both control rooms on March 6, 1997, eliminating

potential impact on the CREVS.*Testing of the~CREVS was conducted in unit 1 on March 13, 1997, to determine system performance

with the drip*,catch basin installed below the return air intake grille.The pan was placed in a configuration

which mimicked the intermittent

position of the unit 2 intake pan during operation of the system for blackout testing.The tests performed verified compliance

with T/S 4.7.5.1 and habitability

dose calculations.

J

Attachment

1 to AEP:NRC:1260C

Page 14 The impact on the unit 1 system was used to analyze the status of the unit 2 system, based on data obtained during the last surveillance

test for unit 2.The result fell well within the acceptable

range required for operability.

Based on the test findings and capability

of the unit 2 pressurization

system, the un'it 2 control room ventilation

system remained operable:with

the catch basin partially'bstructing

the flow.4~5.Corrective

Actions to Avoid Further Violations

The TM procedure,'12-PMP 5040.NOD.001, will be revised'to stress-that-any-installation;-regardless

of whether installed on can operating system or,not, should be considered

a TM if there is reasonable

expectation

that the potential exists to" adversely impact~the

operation of an adjacent system.The pxocedure revision will be completed by June 30, 1997.I As an interim measure until the procedure change can be made, management

will communicate

this event and their expectations

regarding the implementation

of the TM process to those-employees

that may,be involved in making the decision to invoke the TM process.This will be done by June.10, 1997.Date When Full Com liance Will Be.Achieved Full compliance

was achieved on March 6, 1997, whenthe basins were removed.

ATTACHMENT

2 TO AEP:NRC:1260C

RESPONSE TO NOTICE OF DEVIATION

Attachment

2 to AEP:NRC:1260C

Page 1 Notice of Deviation h"During an.NRC inspection

conducted February 16 through March 29, 1997, a deviation of your actions committed to in the updated Final the~~G Safety Analysis Report (UFSAR)was identified.

~In accordanc'th eneral Statement of Policy and Procedures

for NRC Enforcement

Actions, NUREG-1600,'he

deviation is listed below.UFSAR Section 7.4.1-stated, in part,"The power range channels are capable of recording overpower excursions

up to 200 percent of full power."'ontrary-'-to-the--above,-on-February

25;1997, the NRC inspectors

identified

three of four recorder pens":inoperable

for the power range channels that were capable of recording overpower excursions

up to 200 percent of full power.Xn addition, licensee personnel stated that since June of 1991 the-pen's failure rate was such that the percent unavailability

average was 14.9 percent.The pens failure rate was such that they were not capable of recording, overpower--

.=excursions." Res onse to NRC Notice af Deviation Reasons for the Deviation The deviation states that the resident inspector identifi d t hat the power range channels capable of recording excursions

e up to 200 percent of fu11 power, as described in the UFSAR, were found with three'f the four channels incapable of performing

this function.An historical

review identified

that this particular

recording capability

has been challenged

in the.past including significant

periods of recorder unavailability.

The cause for the excessive failures is the relative fragility of the servo-amplifier

electronics

and overall age.The"fragility" of'he electronics

is exacerbated

by the original time response specification

and by the need for speciali2:ed

analog components (state of the art in the late 1960s)to perform this function.The original design philosophy

was to capture the span of the Westinghouse

Nuclear Instrumentation

Power Range channels, 0-200 percent power.In order to capture this range of power, a very fast recorder was believed to be required.The time response requirements

have led to a design that has been difficult and expensive to maintain.Very few replacement

parts are available from the vendor and these recorders will not be able to be maintained

in the near future.The inoperability

periods are influenced

by the fact these recorders are not qui'ckly corrected when identified

as requiring service.Long repair-by dates-are stipulated

by the work control process based on the recorders'egulatory

significance

and the lack of operational

usefulness

on a daily basis.No surveillance

data is required by operators~on these recorders and the normal power level is recorded on different instruments

in the control room.This led to the.lack of attention'o

these recorders by control room operations

personnel.

a~~Attachment

2 to AEP:NRC:1260C

Page 22.Corrective

Actions Taken and Results Achieved 3.Coxrective

action was taken concerning

the three failures noted in this deviation.

The unit 2 recorder 2-SG-14 was calibrated

and the failed pen returned to service on March 13, 1997.Unit 1 was in a refueling outage and the concerns were addressed in section 3 of this response.Corrective

Actions to Avoid Further Deviations

The corrective

actions to avoid further deviations

include improving the control board monitoring

to identify substandard=-equipment,--increase

importance

of all control room instrumentation/recorders

in the work control process, and update the specific recorders mentioned in this deviation to allow ease in their maintenance.

4, These actions were accomplished

by the following changes: The operations

department

standard OPP-1,"Control Room Control Board Monitox'ing

During Non-emergency

Operation Conditions", was revised to stress the importance

of control room panel awareness during every day operation.

This issue was discussed at the following shift manager's meeting and communicated

to the operator crews.The work control standard that placed time requirements

on the repair of critical control room recorders'as revised to include all control room recorders.

Control room recorders requiring maintenance

shall be prioritized

to be woxked within f ive to f ourteen days as determined

by the operations

department

as per the 1997 AEPNGG site operating and maintenance

plan.The Tracor Westronics

recorders were removed f rom unit 1 and their points placed on an existing Yokogawa recorder in the control room.Similar changes are planned for the unit 2 control room instrumentation.

These recorders will allow easier maintenance

and thus reduce the unavailability.

Date When Corrective

Action Will be Co leted The unit 1 corrective

actions wexe completed prior to the restart aftex the refueling outage.Unit 2 corrective

actions will be completed during the next refueling outage scheduled for.the fall of 1997.