ML20137C726

Insp Rept 50-341/85-40 on 850701-1015.Violation Noted: Failure to Adhere to Tech Spec 6.8.1.2 Re Startup of Reactor on 850701 & Failure to Place Control Room Emergency Filtration Sys in Recirculation Mode of Operation

ML20137C726
Person / Time
Site:	Fermi
Issue date:	11/14/1985
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20137C718	List: ML20137C715 ML20137C726
References
50-341-85-40, NUDOCS 8601160395
Download: ML20137C726 (17)

See also: IR 05000341/1985040

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U.S. NL' CLEAR REGULATORY C0m11SSION

REGION III

Report No. 50-341/85040(DRP)

Docket No. 50-341

License No. NPF-43

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Licensee: Detroit Edison Company

2000 Second Avenue

Detroit, MI 48226

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facility Name: Femi 2

Inspection At: Femi Site, Newport, MI

Inspection Conducted: July 1 through October 15, 1985

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Management Meetings At: Glen Ellyn, Illinois on July 23

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and September 10, 1985

Inspectors:

P. M. Byron

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M. E. Parker

D. C. Jones

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)G. C. Wright, Chief

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dG LO

Approved By:

Projects Section 2C;

Date

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Inspection Summary

Inspection on July 1 through October 15, 1985, and Management Meetings on

July 23 and September 10, 1985 (Report No. 50-341/85040(DRP))

Areas Inspected: Special, unannounced inspection by resident inspectors of

activities surrounding the out-of-sequence rod pull, the control room HVAC,

the RCIC/ core spray room cooler, the cooling tower bypass valve, the hydrogen

recombiner and the breach of primary containment integrity. The inspection

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involved a total of 246 inspector-hours onsite by three inspectors including

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77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> onsite during off-shifts. The Management Meetings involved a total of

153 hours0.00177 days <br />0.0425 hours <br />2.529762e-4 weeks <br />5.82165e-5 months <br /> by 26 NRC personnel.

Results: Twenty-sixviblations(includingexamples)wereidentified(seven-

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Limiting Condition for Operations and nineteen - Procedural).

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DETAILS

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Attendees

a.

Persons Attending Management Meeting on July 23, 1985

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Deco

C. M. Heidel President

W. H. Jens. Vice-President, Nuclear Operations

R. S. Lenart, Assistant Manager, Nuclear Production

A. Wegele, Compliance Engineer

D. A. Aniol. Nuclear Shift Supervisor

G. R. Overbeck, Superintendent, Operations

P. A. Marquardt, General Attorney

L. C. Lessor, Advisor, Management Analysis Co.

Public

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B. Campball, Reporter, Detroit Free Press

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NRC HQ's

E. Jordon, Director, Division of EP

B. J. Youngblood, NRR Licensing Chief, Branch No. 1

M. D. Lynch, NRR Licensing Project Manager

NRC RI!!

J. G. Keppler, Regional Administrator

C. J. Paperiello, Director, Division of Reactor Safety

E. Greenman, Deputy Director, Division of Reactor Projects

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N. J. Chrissotimos, Chief, Branch 2. DRP

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L. A. Reyes, Chief, Operations Branch, DRS

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G. C. Wright, Chief. Section 2C, DRP

P. M. Byron, SRI Fermi 2

T. E. Lang, Operator Licensing

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B. Stapleton, Enforcement Specialist

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W. H. Schultz, Enforcement Coordinator

S. Stasek, Project Inspector, Femi

R. B. Landsman, Project Manager, Section 2C, DRP

5. G. DuPont, Reactor Inspector

R. D. Lanksbury, Reactor Inspector

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b.

Persons Attending Management Meeting on September 10, 1985

DECO

C. M. Heidel, President

W. H. Jens, Vice-President, Nuclear Operations

R. S. Lenart Assistant Manager, Nuclear Production

T. Randazzo Director, Regulatory Affairs

E. P. Griffing Assistant Manager, Regulatory Compliance

L. C. Lessor, Advisor, Management Analysis Co.

Wolverine Power Supply

C. Borr, Member, Services Coordinator

J. Gore, Consultant

Public

T. Lam, Reporter, Ann Arbor News

S. Benkelman, Reporter, The Detroit News

B. Campball, Reporter, Detroit Free Press

M. Johnston, Member, Safe Energy Coalition of Michigan

J. Puntennery, Director, Safe Energy Coalition of Michigan

F. Kuron, Monroe County Commissioner

J. Eckert. Director, Office of Civil Preparedness

NRC HQ's

H. D. Lynch, NRR Licensing Project Manager

L. P. Crocker, NRR Licensing Section Chief, Quality Branch

NRC RIII

J. G. Keppler, Regional Administrator

A. B. Davis, Deputy Regional Administrator

C. E. Norelius Director, Division of Reactor Projects

E. Greenman, Deputy Director, Division of Reactor Projects

G. C. Wright, Chief, Section 2C, DRP

P. H. Byron, SRI, Fermi 2

B. W. Stapleton, Enforcement Specialist

J. Strasma. Public Affairs Officer

R. Lickus, Chief. State of Government Affairs

J. A. Hind. Director, Division of Radiation Safety and Safeguards

W. D. Shafer Branch Chief Emergency Preparedness and Radiological

Protection

R. B. Landsman, Project Manager, Section 2C, DRP

C. H. Weil, Compliance Specialist

T. E. Long Operator Licensing

L. Dimmock, Operator Licensing

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2.

Out-of-Sequence Rod Pull

While withdrawing control rods to achieve criticality on July 1, 1985,

the Nuclear Supervising Operator (NS0) pulled eleven control rods in

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Group 3 to position 48 rather than position 04 as required by the control

rod pull sheets.

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The afternoon shift NSO had started pulling control rods around 10:21 p.m.

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EDT on July 1, 1985, and completed pulling centrol rods through step 37

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at 11:15 p.m. EDT.

The night shift NSO started to pull rods at step 38

one minute and eleven seconds later.

The night shift NSO had observed

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the off going NSO for a period of time before taking the controls.

The

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nightshift NSO utilized a Shift Technical Advisor in Training (STAIT) to

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monitor the Source Range Monitor (SRM) instrumentation to facilitate the

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rod pull rather than perform that function himself.

The NSO completed

pulling rods in Group 2 and then commenced pulling rods in Group 3

(step 46).

Starting with step 46 and for the next 10 steps the NSO

pulled each control rod to the full out position (48) rather than

position 04 as required by the procedure.

The NSO verified by his

initials, on the rod pull sheet, that each of the eleven control rods

was at position 04 when in fact they were at position 48.

While pulling the eleventh control rod in Group 3 (control rod 18-51),

the Short Period Alarm annunciated five times and the pen for the

Channel A SRM recorder failed to ink for about three minutes. When

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the pen started inking again the NSO and STAIT observed that recorder

was reading approximately 5x103 counts per second and increasing.

The

Shif t Reactor Engineer (SRE) had predicted that criticality should occur

between steps 150 and 160, when the NSO observed the increasing count

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rata he was only on step 56.

The NSO instructed the STAIT to inform the

Nuclear Shif t Supervisor (NSS) of the situation and immediately started

to insert rod 18-51.

It took 14 minutes and 41 seconds to insert all

eleven control rods to position 04.

Thirty-five (35) seconds later

the NSO continued the startup by pulling rods from step 57 of

the procedure.

During the control rod pulls the NSS and the Nuclear Assistant Shift

Supervisor (NASS) were in the NSS's office.

The SRE was behind the panels

and could not observe the rod pulls.

The NSO in charge of the control

room was at his desk facing the pan 11s and the Shift Technical Advisor

(STA) and the Shift Operations Advisor (50A) were by the NSO's desk,

Neither the NSO in charge, the SOA, nor the STA were observing the rod

pull nor were they aware of the incident.

The STAIT Informed the SRC

of the event who wrote in his log that the reactor may have been

critical.

The NSS reviewed the event with the NSO (at the controls) and the STAIT

and determined that the reactor had not gone critical.

lhe NSS then

directed that rod pulling recommence.

The NSS apparently did not seek

the advice or counsel of the SRE, the SOA, or the S1A,

The SRE also ,

lined out in his log book the reference of the unit being critical.

Neither the NSS nor the NSO logs contained an entry regarding the

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out-of-sequence rod pull.

The NSS, however, did write a Deviation /

Event Report (DER) (No. NP-85-0334) describing the event and stated that

the reactor had not gone critical.

DER No. NP-85-0334 was reviewed by the licensee's Corrective Action

Review Board (CARB) on July 2,1985, who concurred with the NSS's

determination that the incident was not reportable under either 10 CFR 50.72 or 50.73.

It appeared that there was disagreement within the

licensee's organization as to whether or not the reactor had been critical.

The licensee directed that additional engineering review be made.

The

licensee informed the Resident Inspector (RI) of the event on July 3,

1985, and stated that the unit had not gone critical but that there was a

question among the staff and that Reactor Engineering was performing a

technical review.

The licensee stated that they would get back to the

RI when the determination had been made.

The RI informed RIII of his

meeting.

A SRE made the determination on July 4,195 that the reactor had been

critical on July 1, 1985, with a 114 second period and informed his

management of the determination.

Several licensee meetingr. were held on

July 5 and 6, 1985 to discuss this event and to initiate an investigation

into its cause.

The next discussion with the NRC resident staff, af ter July 3,1985,

was on July 15, 1985, when the Senior Resident Inspector (SRI)

was asked by licensee management if he was aware of the July 1, 1985

incident and that the reactor had been critical.

The SRI was aware of

the out-of-sequence rod pull but was not aware that the reactor had

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been critical.

The SRI informed RIII of the meeting, and the new

information on criticality.

Region !!! Issued a Confirmatory Action Letter (CAL-RI!!-85-10) to the

licensee on July 16, 1985.

The CAL detailed the corrective action

the licensee was to take relating to the out-of-sequence rod pull.

The

CAL is detailed in Inspection Report 50-341/85043(DRP).

The licensee

made a presentation in Region III on July 23, 1985, regarding their

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corrective action program and finu ngs related to the event which is

described in Paragraph 9 of this report.

The licensee's presentation

is included as an attachment to their response to the CAL, Deco letter

RC-LG 85-0017 (Jens to Keppler) dated September 5, 1985.

During the inspection and review of the event, nine examples of apparent

violations of Technical Specification requirements were identified and are

as follows:

Technical Specification 6.8.1.a requires that written procedures shall

be estab11shed, implemented, and maintained covering the applicable

procedure recommendations of Appendix A of Regulatory Guide 1.33,

Revision 2, 1978.

Appendix A of Regulatory Guide 1.33 lists the

following activities under Administrative procedures:

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Hot Standby to Minimum Load (Nuclear Startup)

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Authorities and Responsibilities for Safe Operation...

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Equipment Control

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Shift and Relief Turnovers

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Log Entries

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Contrary to the above, the licensee failed to adhere to the provisions of

Technical Specification 6.8.1.a covering the startup of the reactor on

July 1, 1985, as indicated below:

a.

P0M Procedure 51.000.08, " Control Rod Sequence and Movement

Control," paragraph 3.1.1, requires that rod withdrawals in the

region from 100% Rod Density to 20% Reactor Power must be

performed according to the rod pull sheet. The rod pull sheets

in effect on July 1,1985, required the rods for Group 3 to be

pulled in notch control (00-04, 04-08, etc.). The licensee

pulle<* :leven control rods in Group 3 to the full out position

(48) rather than to the 04 position as required (341/85040-01a).

b.

POM Procedure 51.000.08 Paragraph 3.1.4 states, in part, "Following

each rod move the Nuclear Supervising Operator (NS0) shall verify

the control rod was lef t in the proper position indicated and shall

document this verification by initialing the ' Final Position

Verified' block of Attachment 1."

The NSO verified eleven rods to

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be at position 04, by initialinj the pull sheet, when in actuality

they were at position 48(341/85040-01b).

c.

POM Procedures 12.000.57, " Nuclear Production Organization" and

21.000.01, "Shif t Operation and Control Room" delineate the

responsibilittee of the NSS to include supervision of all

activities and observation and/or direction of major plant

evolutions to ensure compliance with Technical Specificatiens,

procedures, and regulations.

The NSS did not appropriately

discharge his duties on July 1 and 2,1985, in that Me neither

supervised, observed, nor directed the activities essociated

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with the control rod pulls (a major plant evaluation) nor was

he in the proximity of the appropriate control panel and

associated nuclear instrumentation (341/85040-01c).

d.

POM Procedur 21.000.01, Enclosure 1

Item 12, requires the Nuclear

Assistant Shif t Supervisor (NASS) to provide direct supervision of

shift personnel. The NASS did not provide direct supervision of the

NSP manipulating the controls on July 1 and 2,1985 nor was he in

the proximity of the appropriate control panel and associated

nuclear instrumentation (341/85040 01d).

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e.

P0H Procedure 21.000.01, Enclosure 2, Item 5 requires the NSO

to be responsible for the plant's main control room operation.

The control room NSO was unaware of the out-of-sequence rod

pull and thus was not successfully discharging his duties

(341/85040-01e).

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f.

POM Procedure 21.000.01, Enclosure 6, Item 2, requires the Shift

Operations Advisor (SOA) observe actuation of annunciators to ensure

that they are being promptly and properly addressed with actions

taken. Five short period alarms were received in less than four

minutes while pulling rod 18-51 on July 1, 1985. The NSO at the

controls was allowed to continue pulling rods and the SOA did not

discharge his responsibilities by failing to become involved in the

resolution of the short period alarms (341/85040-01f).

g.

P0M Procedure 21.000.02, " Operating Logs and Records," Section

4.2.5.8, requires the NSS to record the occurrence of significant

events in the NSS log. The NSS log for July 1 and 2,1985,

contained no entries for the out-of-sequence rod pulls, a

significant event, which occurred between 11:40 and 11:59 p.m.

on July 1,1985(341/85040-01g).

h.

POM Procedure 21.000.01, " Shift Operation and Control Room," Section

6.3.8 states, " Reactor Engineering Administrative Procedure No.

51.000.10, ' Reactor Engineering Conduct of Operations,' details the

duties and responsibilities of on-shif t Reactor Engineering personnel."

Procedure 51.000.10 Section 1.0, states, "The purpose of this

procedure is to outline operational interfaces between Reactor

Engineering and Plant Operations and to clarify the overall responsi-

bilities of on-shif t Reactor Engineering personnel." Procedure 51.000.10

does not detail the duties and responsibilities of the on-shift

Reactor Engineer (341/85040-01h).

1.

POM Procedure 21.000.01, Section 6.8 addresses shift relief and

Section 6.8.4 specifically addresses the control room nuclear

supervisingoperator(NS0). The procedure defines the required

turnover for the NSO in charge of the control room but does not

define any turnuver requirements for the NSO assigned to duties in

the control room but not in charge of the control room (341/85040-011).

3.

Control Room HVAC

On July 11, 1985 PN-21 No. 286934 was issued to inspect the Division !!

Control Room HVAC condensate tray.

For personnel protection the Division !!

Control Room HVAC supply fan control switch was placed in the off position

at 8:35 a.m. on July 18, 1985 and the feeder break was opened and red

tagged at 8:50 a.m.

The Nuclear Supervising Operator (NS0) entered the

action in his log but did not list the Technical Specification appitcability.

The NSO also entered the action in the Control Room Information System

(CRIS) equipment status file and placed the applicable CRIS dot next to

the switch on the sanel. The NSO also advised the protection leader that

protection had to )e removed by 3:00 ).m. on July 25, 1985, however, the

NSO failed to notify the NSS of the c1ange in equipment status. Neither

the NSS log nor the out-of-specification log contain any entries on the

inoperable Division !! HVAC. The work was completed and the request to

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removeprotectionwasmadeat1:20g.m.onJuly 18, 1985. However, the

package was misfiled in the " active file rather thar, the " protection to

be cleared" file.

The out-of-specification condition went unnoticed for 27 shift turnovers

by the oncoming NSS, NASS, and NS0's even though the switch was marked,

a log entry had been made, and it was entered in the CRIS equipment

status file.

It was not until July 27, 1985 that a nightshift NSS

questioned the status of the Division II Control Room HVAC fan and

had the fan returned to service at 5:38 a.m. on July 27, 1985.

During the inspection and review of the event, two apparent violations

of Technical Specification requirements were identified as follows:

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a.

Technical Specification 3.7.2.C.1 requires that with the control

center emergency filtration system supply fan inoperable, with the

plant in cold shutdown, the fan be made operable in seven days or

initiate and maintain operation of the system in the recirculation

mode of operation.

Centrary to the above, the licensee failed to place the control

room emergency filtration system in the recirculation mode of

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operation on July 25, 1985; seven days after the system was

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rendered inoperable on July 18, 1985. This condition existed

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for aroroximately forty-five (45) hours (341/85040-02).

b.

Technicsl Specification 6.8.1.a requires that written prac#dures

shall be established, implemented, and maintained covering the

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applicable procedure reconinendations of Appendix A of Regulatory

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Guide 1.33 Revision 2, 1978. Appendix A of Regulatory Guide 1.33

lists the following activities under Administrative Procedures:

Authorities and Responsibilities for Safe Operation...

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Equipnent Control

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Shif t and helief Turnovers

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Log Entries...

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Contrary to the above, the licensee failed to adhere to the

provisions of Technical Specification 6.8.1.a as follows:

(1) POM Procedure 21.000.01 "Shif t Operations and Control Room,"

delineates the shift turnover responsibilities of the Nuclear

Shif t Supervisor (NSS) the Nuclear Assistant Shift Supervisor

(NAJS) and the Nuclear Station Operator (NS0).

Included in the

responsibilities is a review of past log entries, and a review

of each Combination Operating Panel for off-normal conditions

or the addition of CRIS " dots." The NSS NASS, and NSO all

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failed to adequately perform the required activities as

indicatedbelow(341/85040-03a):

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(a) The Control Center Division II HVAC supply fan switch was

placed in the off position on July 18, 1985, and not

observed to be out of position until July 27, 1985. The

out-of-specification switch position went unobserved for

27 shift turnovers.

(b) The NSO entered the switch position in the equipment

status file and placed a CRIS " dot" by the switch on

July 18, 1985. The CRIS " dot" went unobserved for

27 shift turnovers.

(c) The NS0 had logged placing the Division II Control

Center HVAC supply fan in the off position at 8:35 a.m.

on July 18, 1985. Subsequent reviews of the log either

failed to note the entry or failed to recognize its

significance.

(6 NSS turnovers, 15 NASS turnovers,

and 27 NSO turnovers)

(2) P0H Procedure 21.000.01, Section 6.19.1.1 states, in part.

" Evaluate the consequences of removing the system or component

from service considering such items as Technical Specifications

L.initing Condition for Operations which require an action

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statement to be carried out...."

The licensee failed to

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evaluate the consequences of removing cornponents from service

in that no acknowledgernent of any Technical Specification

applicability was made in either the NSO log of the Control

Room Information System (CRIS) when the Division !! Control

Center HVAC was removed from service (341/85040-03b).

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4.

RCIC/ Core Spray Room Cooler

The NSS observed whilt. reviewing the combination o)erating panels during

his turnover on July 24, 1985, at 6:30 p.m. that tie control switch for

the Division ! Reactor Core Injection Cooling (RCIC)/ Core Spray Room

Cooler was in the off-reset position, this made both RCIC and Division !

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core spray inoperable. The NSS who discovered the out-of-position switch

stated that it was in the proper position at 3:30 p.m. on July 23, 1985.

The Itcensee also determined that the Motor Control Center (MCC-728-3A

Position 20) feeding the room cooler was found in the off position.

Subsequent investigation by the licensee did not reveal any reason for

the coolers status nor could any PN-215 be identified which would have

authorized de-energizing the MCC feeder breaker. The room cooler was

returned to service and the licensee documented the incident in

DER NP-85-0390.

Theunitwasinthestartupmodeofoperation(OperationalCondition2)

at the time the room cooler was taken out of service, but was in a

planned shutdown due to the loss of the South Reactor Feed Pump when

the cooler was found out of service.

(Reactorpressurehadbeenreduced

to less than 150 psig at 7:30 a.m. on July 24,1985.) RCIC is not

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required to be operational below 150 psig; however, the High Pressure

CoreInjection(HPCI)hadbeeninoperablesinceJuly 11, 1985 thus for

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approximately sixteen (16) hours the HPCI, RCIC and Division I core

spray systems were all inoperable.

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During the inspection and review of the event, two apparent violations

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of Technical Specification requirements were identified as follows:

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a.

Technical Specification 3.5.1.C.1 requires that during the startup

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modeofoperation,theHighPressureCoreInjection(HPCI) system

may be inoperable provided that the Core Spray (CS) system, the

Low Pressure Coolant Injection (LPCI) system, the Automatic

Depressurization System (ADS), and the Reactor Core Isolation

Cooling (RCIC)systemareoperable.

Contrary to the above, the licensee failed to ensure that the

RCIC and Division ! core spray systems were operable when they

allowed the RCIC/CS room cooler to be removed from service at

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3:30 p.m. on July 23, 1985 with the HPCI system already inoperable

as of 3:00 a.m. on July 11, 1985. This condition existed for

approximately sixteen hours, with the reactor in the Startup

condition (341/85040-04).

b.

Technical Specification 6.8.1.a requires that written procedures

shall be established, implemented, and maintained covering the

applicable procedure recomendations of Appendix A of Regulatory

Guide 1.33 Revision 2, 1978. Appendix A of Regulatory Guide 1.33

lists the following activities under Administrative Procedures:

Authorities and Responsibilities for Safe Operation...

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Equipment Control

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Shift and Reitef Turnovers

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Log Entries...

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Contrary to the above the licensee failed to ad (n to the

provisions of Technical Specification 6.8.1.a as voilows:

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(1) POM Procedure 12.000.15"PN-21jWorkOrder) Processing,"

Section 7.2.1 states, in part, All work activities at

Fermi 2...sha11 be controlled by a PN-21 and Attachmeet 'A'

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to the PN-21." The licensee failed to write a PN-21 to

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de-energize the feeder breaker (NCC-728-3A Position 20) for

the RCIC/ Core Spray room cooler fan on July 23 and 24,1965

(341/8504005a).

(2) POM Procedure 21.000.01, " Shift Operations and Control Room "

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delineates the shif t turnover responsibilities of the Nuclear

Shif t Supervisor (NSS) the Nuclear Assistant Shif t Supervisor

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(NASS) and the Nuclear Station Operator (NS0).

Included in the

responsibilities is a review of past log entries, and a review

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of each Combination Operating Panel for off-normal conditions

or the addition of CRIS " dots." The NSS, NASS, and NSO all

failed to adequately perform the required activities as the

RCIC/ Core Spray room cooler fan switch was in the "off-reset"

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position for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> on July 23 and 24,1985. The

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normal position for the switch is in the " Auto" position. The

out of position switch went unobserved for two shift turnovers

(341/85040-05b).

(3) P0M Procedure 21.000.01, Section 6.19.1.1 states, in part.

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" Evaluate the consequences of removing the system or component

from service considering such items as Technical Specifications

Limiting Condition for Operations which require an action

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statement to be carried out...."

The licensee failed to

evaluate the consequences of removing components from service

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as he did not take into account the existing inoperability of

the HPCI system prior to removing the RCIC/ Core Spray room

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cooler from service nor was the action entered into the NSO

log or the CRIS equipment status file (341/85040-05c).

5.

Cooling Tower Bypass Valve

On July 26, 1985, while performing surveillance testing on Division I,

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Emergency Diesel Generator (EDG) #11, a Diesel Generator Service Water

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(DGSW) Low Flow Alarm was received. The alarm indicated a lack of

cooling water for the EDG. The operator verified the low flow and

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innediately shutdown the EOG. The licensee, upon further investigatibn.

determined that the mechanical draft cooling tower bypass valve

E1150-F603A was closed and de-energized. This valve is required by a

condition of the license to be open and de-energized, or one of the

cooling tower shutoff valves E1150 F604A/F605A is to be open and

de-energized to prevent spurious closure due to hot shorts in the event

of a fire in the plant. The nomal position for this motor operated

va'te is de-energized and open per POM Procedure 23.208, Revision 8.

Thi . is an apparent violation of License Condition 2.C.(9)(d) (341/85010-06).

Invtstigation into the rcason why the bypass valve was out of proper

position, identified that the valve was last manipulated on July 23,

1985, while running the Reactor Heat Removal Service Water (RHR$W)

system. The valve had exhibited a tendency to trip either the thermal

overloads or the torque switches during stroking and an operator had been

required to partially stroke the valve to the desired position as well as

reset the thermal overloads to allow continued stroking from the control

room.

It appears that clear instructions were not given to the Reactor

Building Rounds Operator as he was not aware of the necessity of leaving

the Ell 50 F603A valve in the open de energized condition.

The E1.50 F603A valve is located in the discharge flow path to the

coolin$ water reservoir and its closure affects multiple systems. With

the valve closed, flow of Erwrgency Equipment Service Water (EESW),

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RHR$W, and DGSW is blocked. Besides affecting the Division I EDG's,

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with the bypass valve closed all Division I emergency core cooling

systems were inoperable including the core spray and residual heat

removal systems.

At the time the bypass valve was discovered in the closed position, the

reactor was in cold shutdown, Condition 4, with the reactor temperature

at approximately 130*F and atmospheric pressure.

In cold shutdown the

plant is required to have one operable division of ECCS, and one operable

divisionofEDG's(twodiesels). This condition was satisfied, however,

the bypass valve E1150-F603A had been closed since about 1:19 p.m. on

July 23, 1985. On July 23, 1985, theunitwasinCondition2(Startup)

which requires both divisions of ECCS and both divisions of the onsite

electrical power source (EDG's) to be operable. As a result of the

bypass valve being closed, only one division was operable. The failure

to take remedial action with one division of the EDG's inoperable is

an apparent violation of T.S. 3.8.1.1.b (341/85040-07).

On July 23, 1985, the licensee connenced a reactor shutdown at about

1:15 p.m. as a result cf the failure of the South Reactor Feed Pums.

It was fortuitous that the licensee coemenced a recctor shutdown a>out

the same time the cooling tower bypass valve was de-energized in 'le

closed position, as the licensee was by chance co.. plying with the

Limiting Condition for Operation (LCO) action statements in reducing

power and proceeding to cold shutdown. Without this action, the plant

would have been in further violation of technical specifications.

6.

Hydrogen Recombiner

On June 20, 1985, the licensee completed maintenance on the Division !!

hydrogen recombiner per Work Order PN-21269327 to replace a leaking

blower seal. The work order stated that post maintenance testing was

required, and identified Plant Operations Manual (POM) Procedures

43.409.01, " Post LOCA Thermal Recombiner System Test," and 24.409.01

" Post LOCA Thermal Recombiner Functional Test." These procedures were

required to demonstrate leak tight integrity and operability,

respectively. The work order was stoned off as completed by the Nuclear

Shif t Supervisor on June 20,1985, w' thout the leakage test having been

perforned per P0M Procedure 43.409.01. This is an apparent violation of

TechnicalSpecifications(T.S.)6.8.1.aand6.8.4.ainthatthelicensee

failed to follow estabitshed procedures and comply with the leakage

reduction program (341/85040 08).

i

On August 26 1985, the licensee initiated a Deviation / Event Report

LNo. I'P-85-0I55) to document the failure to perform the post maintenance

leak rate testing on the Olvision !! hydrogen recombiner. After

the licensee had sufficient

determining the failure to wrfom testing}ner inoperable, as a result

infomation to declare the aydrogen recomb

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of exceeding the 30 day LCO limit, and the licensee did not take action

per technical specification 3.0.3. to place the unit in hot shutdown

,

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_ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ .

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within six hours. The licensee proceeded to determine the leakage rate

and on August 28, 1985, declared the Division II hydrogen recombiner

innperable as a result of the initial leakage rate testing. Subsequently

on August 29, 1985, at 2:46 p.m. the licensee determined that the leakage

rate was in excess of the allowable containment leakage. This is an

apparent violation of T.S. 3.6.6.1, and 3.0.3 in that the licensee failed

to comply with the LCO action statements (341/85040-09).

At 6:00 p.m., on August 29, 1985, the licensee cummenced preparations

to proceed to hot shutdown. The hydrcgen recombiner was repaired, leak

tested, and declared operable on August 29, 1985, at 9:00 p.m.

The plant

was returned to the startup mode with pressure at 950 psig and 3.8% power

for HPCI and SCRAM time testing at 10:40 p.m.

,

During the time period from June 21 to July 21, 1985, the plant entered

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Operational condition (Startup) on five (5) occasions including initial

criticality (June 21, 1985, June 29, 1985, July 2, 1985, July 6, 1985,

and July 10,1985) without both divisions of hydrogen recombiners

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operable. This is an apparent violation of T.S. 3.0.4(341/85040-10).

7.

Breach of Primary Containment Integrity

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ThelicenseediscoveredaContainmentMonitoringSystemValve(T50-071A)

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which is a primary containment boundary, in the open position and uncapped

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on September 2, 1985. The valve was shut upon discovery. The Nuclear

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Shif t Supervisor (NSS) was informed of the event on September 4,1985,

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approximately 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> af ter discovery. ADeviation/EventReport(DER)

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(No.NP-85-0469) was written to document the open valve.

Valve T50-071A was installed under Engineering Design Package (EDP)

No. 1970 dated March 25, 1985. The EDP included the installation of four

test connection cutoff valves in the primary containment monitoring

system. Valves T50-068A and B were installed in piping from the bottom

of the torus while valves T50-071A and B were installed in piping from

the top of the torus. PN-21(WorkOrder)No. 814949 was written to

install the "A" valves in Division I and PN-21 No. 814948 was written to

install the "8" valves in Olvision !!. Both PN-21s were signed off as

" Order Completed" on June 20, 1985.

It should be noted that neither EDP

1970 nor the four PN-21s associated with it were closed out as of

September 10, 1985.

Doth PN-21s for the primary containment monitoring system required Local

Leak Rate Tests (LLRTs) plus Plant Operations Manual Procedure

24.000.05, " Monthly Continuity Light and Channel Check Test," Section 4

" Precautions and Limitations" to be completed. The NSS signed the

PN-21s as order complete on June 20, 1985. The licensee reviewed EDP

1970 and detemined that the LLRTs for the primary containment monitoring

system modifications had not been performed. DER No. NP-85-471 dated

September 5, 1985, was written to document this discrepancy. The licensee

subsequently performed the missed LLRTs and three of the four LLRTs met

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procedural criteria. The LLRT for Penetration.X203A.(P0M Procedure

43.401.386) which contains valve T50-071A did not meet the leakage

criteria. Two of the three boundary valves were repaired and the

penetration subsequently met the test criteria,

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During the inspection and review of the event, three apparent violations

were identified as follows:

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a.

Technical Specification 3.6.1.1 requires that PRIMARY CONTAINMENT

INTEGRITY shall be maintained in Operational Conditions 1, 2,-and 3.

Without PRIMARY CONTAINMENT INTEGRITY restore PRIMARY CONTAINMENT.

e

INTEGRITY within one hour or be in at least HOT SHUTDOWN within the

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next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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Contrary to the above, the licensee failed to maintain containment

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integrity from June 21 to September 2,1985, in that primary

containmentmonitoringsystemvalve(T50-F071-A)wasintheopen

position and the line downstream of the' valve was uncapped which

resulted in an open pathway from the primary containment to the.

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reactor building. Primary containment integrity was required during

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this time frame except for 6.25 days of the interval-(341/85040-11).

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b.

Technical Specification 6.8.1.a requires that written procedures

shall be established, implemented, and maintained covering the-

applicable procedure recommendations of Appendix A of-Regulatory-

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Guide 1.33 Revision 2, 1978. Appendix- A of Regulatory Guide'1.33.

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lists the following activities under Administrative Procedures:

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(1) Equipment Control

(2) Log Entries...

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Contrary to the above, the licensee failed to adhere to the

provisions of Technical Specification 6.8.1.a as follows:

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P0M Procedure 12.000.15, "PN-21 (Work Order) Processing," Revision 11,

August 20, 1985, paragraph 7.3.16 states:

"Upon completion of all-

maintenance, testing, STR or EPC and after_the ' Accepted for Service-

By' slot has been signed, the pink copy-of PN-21 is forwarded to the

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Nuclear Shift Supervisor who will review the order and sign ' Order

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Completed.'" Contrary to the above, the licensee failed to adhere -

to the requirements of POM Procedure 12.000.15. in that Work Order-

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PN-21 No. 814945 (covering the addition of leak rate test conriection.

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valve T50-F071A) was signed " order completed" on June 20, 1985,

without the post installation leak rate testing being performed as.

specified.onthework-order-(341/85040-12)..

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10 CFR 50, Appendix B, Criterion VI,; states, in part,a" Measure. shall:

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be established to control the issuance of documents, such as

instructions, procedures,'and drawings,. including changes'thereto,

which prescribe all activities affecting quality. These measures

shall assure that documents including changes are reviewed for

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adequacy...."

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POM Procedure' 12.000.64, "EDP1 Implementation Procedure,": Revision 2,

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dated March 5, 1985, Section 6.5.1; states, in part, "The responsible

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PSE shall identify the plant documents requiring revision when the -

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package is prepared."

Contrary to the above, the EDP. Implementation Procedure for EDP'

No.1970, covering.the installation of the containment sample system .

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leak rate test connection valve T50-f CIA, did not. identify.all

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the plant documents requiring revision in that it did not identify.

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POM Procedures 24.425.01, " Primary Containment Integrity

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Verification for Valves Outside Containment," or 47.000.77, " Test

Vent and Drain (TVD) Cap:and Plug Verification." The failure to

identify these documents resulted in valve T50-F071A (an_d seven-.

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other valves) not being incorporated into the procedures used to

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verify containment integrity (341/85040-13).

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8. 'Sumary

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Twenty-six -violations (including multiple examples) of NRC requirements

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are identified in this report. The majority of these fall into the

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category of failure to follow procedures._ This represents a-breakdown

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in the licensee's ability to operate the plant in accordance with.

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prescribed procedures as required by the Technical Specifications.

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The licensee's Operational Assurance (0A) organization has a program

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called. Procedure Compliance Module (PCM) which monitors, on a monthly :

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bases, procedural compliance by various organizations. The results'of

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six monthly surveillances (January-June 1985) clearly' revealed that the

operations section had had problems in following procedures. (Procedural

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compliance ran from 74% to 100% and there was no trend--the results were

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erratic. The six-month average was 87% with 99% compliance as a goal.

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It should be noted that the findings of-the PCM program are not absolute

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but are excellent indicators of potential-problem areas. The'results,

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both current and cumulative, are issued monthly. Theslicensee had

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sufficient knowledge of procedural compliance problems to initiate

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corrective actions rather than wait for a larger' data base.

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Seven of the violations were failures to meet Technical Specification

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LimitingConditionforOperations(LC0's).1 Each of these were serious and

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collectively represented a breakdown in the licensee's administrative and

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management controls design to safely operate the plant. The safety;

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significance!of the violations was. mitigated considerably by two' items-

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the plant had only operated for 20 days at an average power of,2 percent;

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and the failure of the South Reactor Feed Pump turbine which resulted in-

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the licensee shutting the reactor down. The inspectors consider the

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second item to be fortuitous.in-that the: reactor was removed from an

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operating condition which required certain equipment to be operable or

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ractions to'be taken when the licensee wasLunaware that the actions or..

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equipment were. required..

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Twenty-six violations, many of them repetitive, have been identified-

in this. report.- Operating history mitigated their safety significance;

however, they demonstrated a major breakdown in the licensee's

administrative controls to safely operate the plant.

9.

Management Meetings

a.

OutJof-Sequence Rod Pull

DECO management.(denoted in Paragraph 1) met with RIII management.

in' Glen Ellyn, Illinois,-on July 23, 1985', to' discuss the sequence of

events surrounding the out-of-sequence rod pull which occurred on

July 1 and 2,.1985, and their subsequent actions. This meeting was,

attended by the public.

The . licensee's presentation included a' detailed sequence.'of events

imediately preceding and following the event, the rod pull _ sheets,

and the Source Range Monitor (SRM) strip chart which. corresponded to-

the time of the incident. .The licensee also presented a layout of

the control room and the relative location in the control room of

those on shift at the time of the event. A great deal of discussion

was focused on the events and licensee' actions subsequent.to the

incident. The adequacy of the onshift review was discussed; RIII's

position was that the onshift review was insufficient. Considerable

discussion was focused around the adequacy, completeness, and

timeliness of the reporting of the incident to the NRC. The

licensee did not consider the event to he reportable under 10 CFRs

50.72 or 50.73. Region III concurred that the incident was.not

reportable under 10 CFR 50.72 or 50.73, but given;the proximity of

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the Comission's full-power briefing, Deco should have been more-

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sensitive to the importance of keeping.the NRC informed.- The

Regional Administrator informed the licensee that he had requested

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the Office of Investigations (OI) to. investigate the event.

The licensee also discussed their actions pertaining to whether or

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not the unit had been critical, as a ' result of the out-of-sequence .

rod pull, and their corrective action. program. The licensee was

informed that Region III would send an inspection team to Femi.2 -

to assess control room operations and the effectiveness of. the -

corrective action program.

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The licensee's presentation is included as-an-attachment to DECO

letter No. RC-LG-85-0017~ (Jens to Keppler) dated September 5, .1985.

b.

Corrective Action Program

DECO management (denoted in Paragraph 1) net with Region III-

management in Glen Ellyn,' Illinois, on September 10, 1985, to discuss

their corrective action program to preclude the repetition of the ~

events which were reported to the NRC during July and. August 1985'and

documented elsewhere in this report. -The meeting was attended by

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representatives of the. Monroe County. Government and the public.

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The licensee proposed a corrective action program based on

observations and recommendations made by the Institute of Nuclear

Power Operations (INP0) assistance inspection team, findings of two

recent NRC team inspections, conditions of the Confimatory Action

Letter (CAL-RIII-85-10) dated July 16, 1985, findings by the

resident NRC inspectors, and recommendations made by Management

AnalysisCorporation(MAC). The program was divided into short

and long term actions. Short term actions were to be completed

prior to power escalation above five percent. Long term actions

addressed programmatic areas with the licensee indicating a phased

implementation to minimize pertubations to plant operations.

Long term actions were to be initiated prior to exceeding five

percent power but not to be completed until some later date with

the longest date of December 1, 1986.

Deco requested that the five percent power restriction be lifted but

that they would commit to not exceeding twenty percent power until

after the forthcoming outage which is scheduled to start during

October 1985. The request was denied.

Region III requested that the licensee docket the corrective action

program which had been presented and include methods of monitoring

the effectiveness of the corrective actions. The licensee

subsequently submitted their " Reactor Operations Improvement

Plan" in a letter from Jens to Keppler (DECO No. VP-85-0198)

dated October 10, 1985 (copy attached).

The licensee was also informed that another inspection team would

be sent to Femi 2 to observe operations and review the corrective

action program and its effectiveness before .the five percent

restriction could be lifted. This action was predicated upon

a satisfactory resolution of the 01 investigation.

10. Enforcement Conference

The NRC staff met with licensee representatives (denoted in Paragraph 1)

during the management meetings and at various times during the inspection

and reviewed the issues discussed in this report.

The staff also discussed the likely informational content of the

inspection report with regard to documents or processes review by the

inspectors during the inspection. The licensee did not identify any

such documents / processes as proprietary.

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