Text

Safety Insp Rept 50-341/85-50 on 851202-06.No Violations Noted.Major Areas Inspected:Verification of Licensee Implementation of Independent Alternative Shutdown Sys
	ML20141F187
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Site:	Fermi
Issue date:	01/03/1986
From:	Dupont S, Gautam A, Guldemond W, Ramsey C; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
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	50-341-85-50, NUDOCS 8601090024
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V. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-341/85050(DRS)

Docket No. 50-341 License No. NPF-43

Licensee: Detroit Edison Company

2000 Second Avenue

Detroit, MI 48224

Facility Name: Enrico Fermi Nuclear Power Plant, Unit 2

Inspection At: Enrico Fermi 2 Site, Monroe, Michigan

Inspection Conducted: December 2-6, 1985

Inspectors y M

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A. Gautam Da'te '

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Approved By. /[f d[gywrr

.W.G.'GuYem,and, Chief

Operational Programs Section

Date

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Inspection Summary

Inspection on December 2-6, 1985 (Report No. 50-341/85050(DRS)1

Areas Inspected: Special safety inspection conducted to verify the licensee's

implementation of an independent alternative shutdown system as required by

Condition No. 2.c.(9)(d) of Facility Operating License No. NPF-43. The

inspection involved 90 inspector-hours by 3 NRC inspectors including 17

inspector-hours onsite during offshifts and 2 inspector-hours conducting

in-office review at the Region III office.

Results: Of the six areas inspected, no violations were identified.

8601090024 B60103

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DETAILS

1. Persons Contacted

DECO

G. Overbeck, Superintendent - Operations

E. Preston, Operations Engineer

R. Anderson, Systems Engineer

S. Heard, Operations

R. Olson, Fire Protection Engineer

D. Holland, Fire Protection Specialist

J. Conen, Nuclear Licensing Engineer

B. Ackerman, Quality Assurance

M. Hobbs, Operations

R. Woolley, Acting Supervisor, Nuclear Licensing

NRC

M. Parker, Resident Inspector

Denotes those personnel in attendance at the December 6, 1985' exit meeting.

2. Alternative / Dedicated Shutdown System Design

By letters dated October 22, 1984 (EF2-72001 and EF2-71994 - W. Jens-DECO

to B. Youngblood - NRC), the licensee comitted to install a postfire

alternative / dedicated shutdown system at the Fermi 2 facility for several

fire areas in the auxiliary building control complex. The proposed design

of this independent shutdown system was reviewed and accepted by the NRC

as discussed in Supplements No. 5 and 6 of the Fermi 2 Safety Evaluation

Report (SER). Condition No. 2.c.(9)(d) of Facility Operating License

No. NPF-43 requires that this system be operational prior to startup

after the first refueling outage or prior to startup after the first

known extended outage of three weeks or longer, whichever occurs first

after September 30, 1985, but not to go beyond December 31, 1986.

The inspectors reviewed this installation as a complete system capable

of accomplishing all of the postfire safe shutdown performance goals

which are necessary to minimize the release of radioact*ivity to the

environment.

a. Systems Provided to Achieve and Maintain Hot and Cold Shutdown

Conditions During and Following Fire

The required systems and associated components are included in the

design to mitigate the adverse consequences of a disabling fire in

the fire areas of concern. With three exceptions (discussed in

paragraphs 6.g.(1), 6.g.(2), and 6.g.(3) of the report), the

capability is provided to achieve and maintain hot and cold shutdown

conditions as follows:

(1) Emergency Power - Combustible Turbine Generator (CTG) No.11,

located in the Unit 1 facility, provides an independent

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(dedicated) power supply for all of the systems and associated

components that are included in the independent alternative

shutdown system design. There are four CTGs of equal capacity

located in the Unit 1 facility which are used for other purposes.

However, only CTG No.11 has black start capability (diesel

engine) which can be initiated from the control room or at the

independent alternative shutdown panel. Once started, it takes 6

.to 10 minutes for CTG No. 'll to provide the power supply needed

for the independent shutdown system. If a fire occurs in one of

the fire areas of concern in coincidence with a loss of offsite-

power, there could be an approximate 10 to 15 minute complete

station blackout (except in areas where 8-hour battery pack

emergency lighting units have been provided) while CTG No. 11 is

being started and the emergency bus is being stripped and

re-loaded with the required essential loads. There is no

designated backup power supply for the system. (This is further

discussed in paragraph 4 of the report).

(2) Maintaining Reactor Vessel and Fuel Cladding Integrity

Circulation of reactor coolant (makeup water) is provided by a

(dedicated) standby feedwater system which takes suction from

the condensate storage tank. Reactor pressure control is

provided by operation of safety relief valves functioning in the

safety mode. The plant can be maintained in a stable hot

shutdown condition by using the standby feedwater system and one

safety relief valve (SRV No. "G") discharging steam into the

torus to control reactor pressure.

(3) Maintaining Containment Integrity and Removal of Decay Heat

Containment isolation can be accomplished by remote controls.

Drywell cooling, torus cooling, and component cooling capability

is provided by (alternative) paths from the Residual Heat

Removal (RHR), RHR Service Water (RHRSW), Emergency Equipment

Service Water (EESW), and Emergency Equipment Cooling Water

(EECW) systems. The capability for control of support systems

such as drywell cooling fans and RHR room cooling fans is also

provided. Cold shutdown can be achieved by placing the RHR

system in the Shutdown Cooling Mode.

Required instrumentation such as reactor level and pressure,

standby feedwater flow rate, torus water temperature and level,

condensate storage tank level, bus voltage monitor, and primary

containment temperature indications are provided on the indepen-

dent alternative shutdown (3L) panel. Isolation transfer

switches and local controls which are independent of the fire

areas of concern are provided on the 3L panel and at various

locations in the reactor building for required breakers and

motor control centers. The instrumentation provided meets NRC

guidelines for BWRs.

No violations or deviations were identified.

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3. Functional Testing to Determine Operability of the System

The inspectors reviewed the following test procedures and resultant data

and determined that the functional testing demonstrated the operability

of the system described in preceding Paragraph 2.a.

a. 47.000.83, Revision 0, " Third Remote Shutdown Panel (C3600)

Supervisory Control Testing and Calibration."

The objective of the test was to evaluate the technical performance

of the telemetering linking of the Third Remote Shutdown Panel (3L)

at Fermi 2 to CTG-11-1 and controls at Fermi 1. The subsystems

tested included the Fermi 2 master control and transfer, Fermi 1

remote control and transfer, status indicators, and the undervoltage

trip scheme.

b. 48.000.05, Revision 0, " Remote Shutdown Panel (3L) H21-P623 Post-

Modification Test."

The objective of the test was to verify the transferring of the

control of the Appendix R alternative shutdown system from the

-Fermi 2 control room to the Remote Shutdown Panel (3L) by verifying

positive and negative component operation, and a simulated loss of

offsite power to demonstrate control of the 120 KV MAT and CTG-11

from the remote shutdown panel.

c. 24.321.01, Revision 0, " Remote Shutdown System (3L) Operability

Verification."

The objective of the test is to verify the operability of the entire

Remote Shutdown Panel (3L). The testing will include actual verifi-

cation of transferring control of the affected components from the

Fermi 2 control room to the 3L panel. This is a surveillance test

to verify the operability of the system at an 18 month frequency

which was initially tested after modification by procedure 47.000.83.

as described above. The inspectors verified that the test included

positive and negative verification checks.

No violations or deviations were identified.

4. Proposed Technical Specifications

By letter dated September 27, 1985 (RC-LG-85-0051, W. Jens --DECO to

B. J. Youngblood - NRC), the licensee requested an amendment to technical

specifications for the independent alternative shutdown system. The

technical specifications define limiting conditions for operation of the

alternative shutdown system that appear to be consistent with the "Model

Technical Specifications for Alternative Shutdown Systems" required by

10 CFR Part 50, Appendix R (NRC Internal Memorandum dated March 10, 1983,

M. Virgilio to T. Wambach). In addition, the licensee proposed limiting

conditions for operation for several components used in the independent

alternative shutdown system that are not described in the "Model Technical

Specifications for Alternative Shutdown Systems."

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The inspectors' review indicated that the licensee's proposed technical

specifications and amendment were satisfactory except as follows:

The action statement (3/4.7.9) as proposed for the loss of CTG No.11

requires verification that 120 KV offsite power is available to supply

power to the shutdown panel and establishment of a roving fire watch for

all fire areas where alternative shutdown capability is utilized. The

licensee believes the availability of 120 KV power and a roving fire watch

in the fire areas of concern to be sufficient to allow a period of up to

30 days in which either to restore CTG No. 11 to an operable status or

provide an alternative power supply. Within 60 days, the licensee

proposes to restore CTG No.11 to an operable status or be in at least hot

shutdown within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and be in ~old c shutdown within the

following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The inspectors informed the licensee that, based on discussions with NRR

during the inspection, a designate _d backup power supply other than 120 KV

offsite power will have to be made available within 30 days if CTG No.11

is inoperable for more than 30 days.

At the conclusion of the inspection, the licensee agreed to designate this

backup power supply either by providing one of the remaining CTG units with

black start capability or by supplying another alternate source of power.

The licensee indicated that this commitment would be formally transmitted

to NRR and reflected in the proposed technical specification bases or in

some other document. The inspectors informed the licensee that this issue

must be resolved prior to startup from the current outage. This is

considered an Open Item (50-341/85050-01(DRS)) pending verification by NRR

and Region III prior to startup from the current outage.

No violations or deviations were identified.

5. Proposed Technical Specification Surveillances

The inspectors reviewed the proposed Technical Specification Table 4.3.10,

" Appendix R Alternative Shutdown Instrumentation and Controls Surveillance

Requirements" and various surveillance procedures to verify that procedures

exist for the required instrument channel calibration and checks. The

following procedures were verified to satisfy the Technical Specification

requirements:

44.110.26, Revision 0, " Alternative Shutdown System Primary

Containment Temperature Channel Calibration."

44.110.25, Revision 0, " Alternative Shutdown System Torus Water

Level Channel Calibration."

44.110.24, Revision 0, " Alternative Shutdown System Torus Water

Temperature Channel Calibration."

44.110.23, Revision 0, " Alternative Shutdown System Reactor

Pressure Channel Calibration."

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' 44.110.22, Revision 0, " Alternative Shutdown System Reactor

Water Level Channel Calibration."

44.110.21, Revision 0, " Alternative Shutdown System Standby Feedwater

Flow Channel Calibration."

44.110.20, Revision 0, " Alternative Shutdown System Condensate

Storage Tank Level Channel Calibration."

24.324.01 (draft) Revision 0, " CTG-11-1 Monthly Operability Check."

In addition to reviewing the above Technical Specification surveillance

procedures, the inspector verified that the following control room alarm

procedures correctly addressed the Appendix R alternative shutdown

Technical Specification 3.3.10. " Appendix R Alternative Shutdown Instru-

mentation and Controls" and 3.7.9, " Appendix R Alternative Shutdown

Auxiliary System":

ARP11D49, Revision 0, " Dedicated Shutdown Supervisory Control

Activated."

ARP11D53, Revision 0, " Dedicated Shutdown Supervisory

Control Trouble."

ARP11D57, Revision 0, "120 KV Undervoltage Scheme Abnormal."

ARP 11061, Revision 0, " Dedicated Shutdown Transfer Pushbutton Armed."

No violations or deviations were identified.

6. Reanalysis of Associated Circuits

Supplement No. 5 of the SER required that the licensee perform a reanalysis

of those circuits which could have an adverse affect on the proper func-

tioning of the independent alternative shutdown capability.

On a sample basis, the inspectors reviewed certain of these circuits to

verify their electrical and physical isolation from the fire areas of

concern. To prevent some spurious actuations due to fire damage to

circuits, the licensee installed acceptable isolation transfer switches.

In other instances (for example, core spray and RCIC systems), the

licensee elected to strip the loads off of Class IE AC and DC buses. In

addition, to prevent spurious actuations from adversely affecting

reliability of CTG No. 11 operation, selected balance of plant (80P) loads

are also stripped from the 80P AC and DC buses prior to re-energizing.

The associated circuit concerns evaluated were:

a. Comon bus associated circuits - The comon bus concern is found in

circuits, either non-safety related or safety-related, where there

is a comon power source with shutdown equipment and the power source

is not electrically protected from the circuit of concern.

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b. Comon enclosure associated circuits - The common enclosure concern

is found when redundant circuits are routed together in a raceway or

enclosure and they are not electrically protected or fire can destroy

both circuits due to inadequate fire protection means.

c. Spurious signal associated circuits - The spurious signal concern

consists of two parts:

(1) False motor, control, and instrument readings such as occurred

at the 1975 Brown's Ferry fire. These indications could be

caused by a fire initiated ground, shorts, or open circuits.

(2) Spurious operation of safety related components that would

adversely affect shutdown capability (e.g., RHR isolation

valves).

d. The following schematic and wiring diagrams were reviewed:

(1) H21-P623 Dedicated Rcmote Shutdown (3L) Panel.

Drawings 6I721-2782-1, Revision 0,

6I721-2783-1, Revision 0,

61721F-2592-2, Revision 0,

61721F-2592-3, Revision 0

(2) EF1-EF2 Supervisory Control Panels, "3L" System Remote.

Drawings 6SD721F-150, Revision 0,

6SD721-163, Revision 0,

6SD721-166, Revision 0,

6SD721-164, Revision 0,

6SD721-165, Revision 0

(3) H21-P625 Dedicated Local Control Panel, Transfer Control

from MCC 72C-3A

Drawings 61721-2201-78, Revision 0,

6I721-2201-75, Revision 0

(4) H21-P626 Dedicated Local Control Panel, Transfer Control

from MCC 72B-3A

Drawings 6I721-2201-71, Revision 0,

61721-2201-79, Revision 0

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(5) H21-P627 Dedicated Local Control Panel, Transfer Control

from MCC MCC 72C-F

Drawings 6I721-2201-81, Revision 0,

61721-2201-80, Revision 0

(6) N21083-F001 Standby Feedwater Isolation Valve Motor

Operator (M0)

Drawing 61721-2317-28, Revision 0

(7) N2103-F002 Standby Feedwater Control Valve M0

Drawing 61721-2317-29, Revision 0

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(8) N2103-F003 Standby Feedwater Flow Control Valve M0

Drawing 61721-2317-30, Revision 0-

-(9) Dedicated Shutdown System Diagram 6I721-2784-7, Revised

June 6, 1985

(10) One line diagram, Plant 4160V and 480V System Service

Drawing 6SD721-2500-1, Revision 1

(11) 4160V, Bus 65W Incoming Breaker

Drawings 61721-2311-40, Revision A

6SD721-2501-81, Revision A

(12)4160V, Bus 64VIncomingBreaker

Drawings 6I721-2311-39 Revision A

6D721-25'J1-85, Revision B

61721-2315-8, Revision A

(13)4160V, Bus 64V,65W.TieBreaker,PosV3

Drawings 61721-2311-41, Revision 0

6SD721-2501-83, Revision A

(14) N2103-C001 Standby Feedwater System Pump A, Bus 64V

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Drawings 61721-2311-35, Revision 0

65D721-2501-82, Revision A

(15) N2103-C002 Standby Feedwater System Pump B, Bus 65W

Drawings 61721-2311-36, Revision 0

6SD721-2501-84, Revision 0

e. Electrical Isolation - Common Bus, Common Enclosure, and

Spurious Operation Concerns

CTG No. 11 and the Standby Feedwater System are dedicated systems

that are electrically independent of the fire areas of concern. The

"3L" (remote shutdown) panel No. H21-P623, as well as the 4160V

switchgear for buses No. 64V and 65W are physically located in the

radwaste building outside the fire areas of concern. According to

the licensee, all controls and instrumentation circuits for the "3L"

panel are provided with dedicated transmitters that will not be

affected by a fire in the areas of concern.

For example, for a fire in the control room, supervisory switch

No. EF1 on panel No. H21-P623 (3L panel) can be placed in the local

position. This allows a signal to be transmitted using the tone

signal generator inmodem in the supervisory control panel to initiate

starting of CTG No. 11. By placing the system transfer switch

No. EF2 on the "3L" panel to the local position, dedicated relays

in 4160 volt switchgear in conjunction with controls at the "3L"

panel, allow for remote operation of the Standby Feedwater System

and associated valves that provide a flow path for reactor coolant

makeup from the condensate storage tank. Control circuits for the

standby feedwater pumps and valve motor operators have been modified

in accordance with Engineering Design Packages (EDPs) No. 1701 and

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1702, Revision 0. Fuses and control switches have been added to

these circuits in order to isolate them from damage resulting from

fires in the areas-of concern.

The circuitry to standby feedwater pump No. AN2103C001 (drawing

No. 61721-2311-35, Revision 0), was modified to add new 50 Amp and

30 Amp fuses, and Relays No. 43X/K1V2 and 43X/K2V2 in the 4160 volt

switchgear. This permits isolation of circuits in the control room

by transferring Switch No. EF2 on the "3L" panel to the local

position. When in the local position, Switch No. EF2 on the "3L"

panel transfers power and control of Standby Feedwater Pump No. A

and its associated valves to a separate circuit that is electrically

isolated from the fire areas of concern.

Panel No. H21-P623 also provided breaker control for offsite 120KV

power breakers GM, GK, GH, and GD, as well as controls for CTG 11 and

associated breakers which provide a dedicated source of power

for buses 64C, 64V, and 64W and associated shutdown equipment during

a fire in the referenced fire areas. In the event of a fire in

panel No. H21-P623,120KV breaker control could be lost. However,

according to the licensee, this power source can be retained at the

control room, or another 345KV offsite power source can be used for

control of breakers from the control room. All other controls on the

dedicated shutdown panel No. H21-P623, including SBFW pumps, safety

relief valves, and instrumentation, could be lost at the "3L" par.el

without adversely affecting safe shutdown from the control room. In

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this case, safety-related Division I and II ECCS would still be

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available.

The circuitry for local control panel Nos. H21-P626 and H21-P627 was

also reviewed. Both panels were found to have appropriate isolation

through fuses, relays, and transfer switches so that RHR loads on

MCC No. 72C-F and MCC No. 72B-3A can be transferred to separate

circuits that are electrically independent of the fire areas of

concern.

By placing all transfer switches on local control panel No. H21-P627

in the local position, controls for RHR Loop A and B discharge and

isolation valve Nos. E11-F010, F015A, and F017A are isolated from

the control room. Transfer switches No. 435-3A and 435-2C allow for

control of the isolation valves through a new set of fuses and

contacts that are independent of the fire areas of concern.

The licensee indicated that sirailar modifications have been completed

for all the circuitry to the systems and components that are included

in the independent alternative shutdown system,

f. Cable Separation Division II Remote Shutdown Panel

By letter dated November 27, 1986 (VP-85-0215, W. Jens - DECO to

B. J. Youngblood - NRC), the licensee informed the NRC that Detroit

Edison has decided not to electrically disable the Division II remote

shutdown panel until completion of the installation of the "3L" panel

system. Detroit Edison committed to disable the Division II remote

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shutdown panel in order to resolve NRC concerns about Class IE and

non-class 1E interfaces in the panel. This commitment was made in

the licensee letter No. VP-85-0132 dated June 5, 1985 in response

to Region III Inspection Report No. 50-341/85009.

According to License Condition No. 2.c.(9)(d) of Facility Operating

License No. NPF-33,.the "3L" panel must be operational prior to

startup after the present outage. Therefore, the licensee has

inferred that the Division II remote shutdown panel will be electri-

cally disabled prior to startup from the present outage.

This is an Open Item (341/85050-02) pending verification by Region III

prior to startup from the current outage.

g. Cable Separation Independent Alternative Shutdown ("3L") Panel

During their review the licensee identified three electrical cable

feeds used in the independent alternative shutdown system that are

routed through the fire areas of concern for which the shutdown system

is provided. A fire in these areas could disable normal shutdown

systems as well as the independent alternative shutdown system. This

is in conflict with commitments made to the NRC by the licensee in

Correspondence No. EF2-72001, dated October 22, 1984 (W. Jens - DECO

to B. J. Youngblood - NRC).

The following cables are routed through the fire areas of concern:

(1) Electrical feed cable No. R.I. 005 2P, supplying power to

distribution cabinet No. ZPB-2,-which supplies power to safety

relief valve (SRV) No. F013G solenoid (enabling control of the

SRV from the independent alternative shutdown panel), is routed

into Fire Zone 8 at the 631 foot elevation of the auxiliary

building. This cable originates at the Division II battery

room, passes through Fire Zone 8 of the auxiliary building and

terminates at the ZPB-2 distribution cabinet.

To correct this condition, the licensee installed a 3M brand

one-hour fire barrier wrap on this cable throughout its exposure

to Fire Zone 8. Fire Zone 8 is protected by an autcmatic carbon

dioxide fire suppression system and automatic fire detectors.

The inspectors informed the licensee that the corrective actions

taken for this condition were found to be in conformance with

Section III.G.2.c of Appendix R to 10 CFR 50. However, the

condition and corrective actions taken must be formally

submitted by the licensee to NRR for acceptance.

This is considered an open item (341/85050-03) pending

verification of NRR acceptance of the licensee's corrective

actions prior to startup from the current outage.

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(2) Calvert Bus

Additionally, the 4160 volt feed between the Division 1

Switchgear Room Buses and the Radwaste Switchgear Room Buses

was found to be routed through the cable area at the 603'-6"

level of the Auxiliary Building. This location is one of the

fire areas of concern. The 4160 volt feed is also known as the

Calvert Bus and is part of the power supply for the Appendix R

Dedicated Shutdown System (3L). The inspectors verified the

Calvert Bus location visually and by reviewing the drawings

6E721-2988-1 through 5.

Because the Calvert Bus is unprotected, a fire in the Auxiliary

Building Fire Zone 2 could cause the loss of power to the SBFW

pumps as well as the loss of normal shutdown systems. To correct

this condition, the licensee has proposed wrapping all the

divisional power, instrumentation, and control cables in the

Fire Zone 2 in a 3M brand one-hour firewrap material. By

wrapping the Divisional cables, the licensee's intent is to meet

the requirement of Appendix R, SectionIII.G.2 in this zone.

This zone is provided with an automatic suppression system and

-fire detection.

The inspectors informed the licensee that the proposed corrective

actions for this condition deviates from a previous commitment

to conform to Section 3.L of Appendix R in this zone. Therefore,

acceptability of the resolution to this condition must be

pursued with NRR.

This is considered an open item (341/85050-04) pending verifica-

tion of NRR's acceptance of the licensee's corrective actions

prior to startup from the current outage.

(3) Reactor pressure, reactor level, torus temperature, torus

level and EECW instrumentation cables for the independent

alternative shutdown ppnel are routed in Fire Zone 1 at the

551 to 562 foot eleva(ion of the Auxiliary Building (basement).

Some cables in this zone are partially wrapped in 3M brand

one-hour fire barrier material. This zone is protected by

an automatic sprinkler system and automatic fire detectors.

According to the licensee, corrective actions taken for these

conditions will be in conformance to Section III.G.3 of

Appendix R to 10 CFR 50.

The inspectors informed the licensee that the corrective actions

taken for these conditions must be fonnally submitted by the

licensee to NRR for acceptance.

This is considered an open item (341/85050-05) pending

verification of NRR acceptance of the licensee's corrective

actions by Region III prior to startup from the current outage.

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(4) Spurious Operation of Various Valves

Supplement No. 5 of the SER described spurious operation of

various valves in the RHR and HPCI systems from multiple hot

shorts. As resolution, the SER required power be removed from

one or two of the RHR suction isolation valves and the test

return valve from the RCIC and HPCI systems to the CST. The

inspectors reviewed the following procedures and documents,

and verified that the licensee's actions are in agreement with

the SER:

23.202, Revision 8, "High Pressure Coolant Injection System

(HPCI)."

23.205, Revision 6, " Residual Heat Removal System (RHR)."

Engineering Design Package (EDP) - 4200, Revision A,

" Restoration of Valve Position Indication During Circuit

De-energization for E1150-F008 and E4150-F011."

No violations or deviations were identified.

7. Supplemental Procedures Developed to Implement the Independent

Alternative Shutdown System

a. Methodology

The inspectors reviewed the abnormal operation procedure 20.000.18,

" Control of the Plant From the Dedicated Shutdown Panel", and

determined that, initially, the procedure did not meet the intent

of Supplement No. 5 of the SER in that a 10 minute assessment period

was included in the immediate operator actions section of the

procedure. The above methodology was included in the licensee's

response EF2-72001 to Mr. B.J. Youngblood (Division of Licensing,

NRC) dated October 22, 1984 but was not included in the supplement to

the SER. The purpose of the 10 minute assessment was to evaluate if

the fire was extinguished or not and what actions to take. However,

Appendix R and the SER do not allow for a delay in actions based on

time to extinguish the fire but require immediate actions to control

the plant and to achieve Hot Standby. The licensee agreed and

revised the procedure by removing the 10 minute assessment methodology

and required immediate actions to control the plant in Hot Standby

and to achieve Cold Shutdown as required by Appendix R. In addition

to the above methodology, the inspectors verified that the remainder

of the procedure did agree with Appendix R and the supplement to the

SER in that the reactor is scrammed, reactor vessel level and pressure

control is assured at the remote shutdown panel by using Standby

Feedwater (SBFW) and the dedicated Safety Relief Valve (SRV),

electrical loads are stripped and the dedicated safe shutdown loads

for Hot Standby are restored by supplying the dedicated buses from

CTG-11-1, and that primary containment torus and long-term shutdown

cooling are lined up.

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b. Walkdown

The inspectors witnessed a walkdown of the procedure by two operators.

During the walkdown the inspectors verified the locations of the

local panels, availability of procedures at the local panels, and the

methodology of the revised procedures. However, two open inspection

items were identified: due to locations, time required, and com-

plexity of the operator actions at the local panels, the evolutions

require three operators - one operator to control reactor vessel

pressure and level at the Remote Shutdown Panel and two operators

performing the local lineups. The procedure currently requires only

two operators, one at the Remote Shutdown Panel and one performing

the local operations. The licensee committed to include instructions

in the operator's night-order book or the procedure to utilize two

operators for the local operations. This is an open item (341/85050-06)

until the licensee's commitment is verified. In addition to the

manpower requirement above, communication is also identified as an

open inspection item (341/85050-07) in that due to the distance and

time requirements of the evolutions, portable radios are needed to

assure the completion of the local operations. The licensee has

committed to provide portable radios at the Remote Shutdown Panel for

use by the two operators performing the local operations.

The inspectors reviewed the communication survey and verified that

at all loceL panel and operation locations, good radio reception is

achievable.

c. Training

The inspectors attended one training session on the abnormal

operation procedure 20.000.18 and found it to be satisfactory.

The training included the details of the procedure, methodology,

and a walkdown in the plant with hands-on demonstration. In

addition, the licensee has scheduled retraining by operator shifts

to ensure that icmiliarity is maintained as part of the operator's

retraining and certification program.

No violations or deviations were identified.

8. Open Items

Open items are matters which have been discussed with the licensee, which

will be reviewed further by the inspectors, and which involve some action

on the part of the NRC, the licensee, or bcch. Open items disclosed

during the inspection a.-c. discussed in Paragraphs 4, 6.f, 6.g.(1),

6.g.(2), 6.g.(3), and 7.b. These items are required to be resolved prior

to startup frcm the current outage.

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9. Exit Interview

The inspectors met with the licensee representatives at the conclusion

of the inspection on December 6, 1985, and summarized the scope and

findings of the-inspection. The licensee acknowledged the statements

made by the inspectors. The inspectors also discussed the likely infor-

mational content of the inspection report with regard to docucents

reviewed by the inspectors during the inspection. The licensee did not

identify any.such documents as proprietary. On December 18, 1985, in a

telephone conversation with the licensee, additional concerns regarding

associated circuits for the independent alternative shutdown system

were discussed with the licensee.

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ML20141F187

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