ML17333A910
| 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
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.