ML20137S940

Insp Rept 50-416/85-46 on 851221-860117.Violation Noted: Failure to Follow Procedures for Placing Shutdown Cooling in Effect & to Maintain Reactor Vessel Water Level & Feedwater Pump Discharge Pressure

ML20137S940
Person / Time
Site:	Grand Gulf
Issue date:	02/04/1986
From:	Butcher R, Caldwell J, Dance H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20137S877	List: ML20137S874 ML20137S900 ML20137S940
References
50-416-85-46, IEIN-85-094, IEIN-85-94, NUDOCS 8602180147
Download: ML20137S940 (12)

See also: IR 05000416/1985046

Text

s

pa iE4 UNITE 3 STATES

,

4 q'o NUCLEAR REGULATORY COMMISSION

[ , REGION li

g

.j 101 MARIETTA STREET, N.W.

• ATLANTA, GEORGI A 30323

\...../

Report No.: 50-416/85-46

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Licensee: Mississippi Power And Light Company

Jackson, MS 39205

Docket No.: 50-416 License No.: NPF-29

Facility Name: Grand Gulf Unit 1

Inspection Conduc ed: December 21, 1985 - January 17,.1986

Inspectors: &% o >

R.' C utche Senior / sident Inspector (Tatd Signed

OW _

U h (o

J. . Caldwell, Resident Inspector Bate Si ned

Approved by:

H. C. Dance,TChief, Project Section 2B

[N

Da'te '51gned

Division of Reactor Projects

SUMMARY

Scope: This routine inspection entailed 177 resident inspector-hours at the site

in the areas of Operational Safety Verification, Maintenance Observation,

Surveillance Observation, Cold Weather Preparations, Reportable Occurrences,

Operating Reactor Events, and Inspector Followup and Unresolved Items.

Results: Violation - Three examples of failure to follow procedures'for placing

shutdown cooling in effect, to maintain reactor vessel water level and feedwater

pump discharge pressure as required.

8602180147 960207

PDR ADOCK 05000416

G PDR

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REPORT DETAILS

1. Licensee Employees Contacted

• J. E. Cross, Site Director

• C. R. Hutchinson, General Manager >

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~*R.' F. Rogers, Technical Assistant

• J. D. Bailey, Compliance Coordinator

M. J.. Wright, Manager, Plant Operations

• L. F. Daughtery, Compliance Superintendent

D. Cupstid, Technical Support Superintendent

R. H. McAnuity, Electrical Superintendent -

R.-V. Moomaw, Manager, Plant Maintenance

-B. Harris, Compliance Coordinator

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J. L. Robertson, Operations Superintendent

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L. Temple, I & C Superintendent .

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J. Mueller, Mechanical Superintendent 'g

Other. licensee employees contacted included technicians, operators, securfty

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force members, and office personnel.

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• Attended exit interview

2. Exit Interview t.['

The inspection scope and findings were summarized on January 17, 1986, with '

those persons indicated in paragraph I above. The licensee did not identify

as proprietary any of the materials provided to or reviewed by the

inspectors during this inspection. The licensee had no comment on the

following inspection f.indings:

a. 416/85-46-01, Violation. Failure to follow procedures for placing '

~s hutdown cooling in effect when in operational condition 2. Failure to \

follow procedures to maintain reactor. vessel water';evel and reactor

feed pump discharge pressure as requ' ired. (Paragraph 5.a and 9.e)

b. 416/85-46-02, IFI. Licensee prepare comprehensive procedure for

placing shutdown cooling in effect when in operational condition 2.

.(Paragraph 5.a)

c. 416/85-46-03, IFI. Incorporate requirement to declare affected

Emergency Core Cooling System (ECCS) inoperable when minimum flow path "

is unavailable. (Paragraph 5.b)

d. 416/85-46-04, IFI. Documentatien of 'significant events that are not

reportable by the licensee. (Paragraph 9.a)

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e. 416/85-46-05, IFI. Prepare comprehensive cold weather preparations

procedure. (Paragraph 11)

3 .' Licensee Action on Previous Enforcement Matters (92702)

a. (Closed) Deviation- 416/85-28-01. The_ _ Surveillance Procedure

06-0P-1C61-R-0002 committed to be issued by August 31, 1984 in letter

AECM 84/0418 dated August 20, 1984 was issued on August 30, 1985. This

item is closed.

b. (Closed) Vio.lation 416/85-22-01. The inspectors reviewed the

corrective actions taken by the licensee and found them acceptable.

Subsequent inspections have not revealed any recurrence of this

violation. This item is closed.

4 Unresolved Items

Unresolved items were not identified during this inspection.

.5. Operational Safety Verification (71707)

.

The inspectors kept informed on a daily basis of the overall plant status

and any .significant safety matters related to plant operations. Daily

discussions were held with plant management and various members of the plant

operating staff.

The inspectors made frequent visits to the control room such that it was

visited at least daily when an inspector was on site. Observations included

instrument readings, setpoints and recordings status of operating systems;

tags and clearances on equipment controls and' switches; annunciator

alarms; adherence to limiting conditions for operation; temporary alterations

in effect; daily journals and data sheet entries; control room manning; and

access controls. This inspection activity included numerous informal

discussions with operators and their supervisors.

Weekly, when onsite, selected ESF system were confirmed operable. The

confirmation is made by verifying the following: Accessible valve flow path

alignment; power supply breaker and fuse status; major component leakage,

lubrication, cooling and general condition; and instrumentation.

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General plant tours were conducted on at least a biweekly basis. Portions

of the control building, turbine building, auxiliary building and outside

areas were visited. Observations included safety related tagout verifica-

tions, shift turnover, sampling program, housekeeping and general plant

conditions, fire pactection equipment, control of activities in progress,

radiation protection controls, physical security, problem identification

systems, and containment isolation. The following comments were noted:

a. On Decen:ber 22, 1985, the licensee initiated a reactor startup

following an outage- to repair ~ some condenser tube leaks. At 11:27

a.m., the reactor mode switch was placed in startup (operational

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condition 2). Control rod withdrawal was initiated at 11:31 a.m. At

12:25 p.m. with the reactor subcritical, the B Residual Heat Removal

(RHR) system was placed in the shutdown cooling mode to maintain plant

conditions. This made the Low . Pressure Coolant Injection (LPCI) B

system inoperable and the plant entered action statement b.1 of

Technical Specification (TS) 3.5.1 which states "with either LPCI .

subsystem B or C inoperable, restore the inoperable LPCI subsystem B or l

C to operable status within 7 days." The licensee used the provisions

of a special test exception in TS 3.10.5', Training Startups, which

permits one loop of RHR to be aligned for shutdown cooling for training

startups provided the reactor vessel is not pressurized, thermal power

is less than or equal to 1% of rated thermal power and reactor coolant

temperature is less than 200 F.

A similar reactor startup on June 6, 1985 was discussed in Report 85-20

and the licensee had committed to referencing the requirements of

TS 3.10.5 in their procedure to ensure the operators are aware of the

requirements. This was inspector followup item 416/85-20-03. The

licensee revised Integrated Operating Instruction (I0I) 03-1-01-1, Rev.

30, paragraph 2.1.11 to state "with shutdown cooling inservice, while

performing cold criticalities, limit the reactor coolant temperature

to less than or equal to 150 F and thermal power less than or equal

to 1%." Paragraph 5.26 states "If reactor startup is for training

purposes per TS 3.10.5, or cold criticals begin recording reactor

vessel unpressurized, thermal power and reactor coolant temperature on

Data Sheet III. These readings must be taken hourly."

At 12:15 p.m., the.A and B recirculation loop suction temperatures were

189"F and 188 F respectively which exceeds the temperature limits

specified in 101 03-1-01-1. At 2:00 p.m., the A and B recirculation

loop suction temperatures were both 159*F indicating a cooldown of 30*F

(which is an appreciable positive reactivity addition) in less than two

hours. During this period, data sheet III of 10I 03-1-01-1 was nct

being used. TS 6.8.1 requires written procedures be Jestabli shec ,

implemented and maintained covering the procedures recommended in

Appendix A of Regulatory Guide (RG) 1.33. RG 1.33 requires written

procedures for plant operation from hot standby to minimum load. The

failure to follow I0I 03-1-01-1 is a Violation (416/85-46-01). Other

examples of procedural violations are discussed in paragraph 9.e.

r Discussions with the Manager, Plant Operations, indicate that he

thoroughly discussed the above evolution with the on shift operations

personnel and they were aware of the plant conditions. The resident

inspector contacted Region II supervision and NRR regarding the

incorporation of shutdown cooling during startup for other than

training or cold criticalities. Certain other facility TS have

provisions for operating shutdown cooling while in operational

condition 2 (startup) and, if properly controlled, such operation is

permissible. The resident clso confirmed that NRC does not consider

all potential plant evolutions not specifically prohibited and/or

discussed in TS to be permissible. A conservative approach to plant

operations is recommended when off normal operational conditions arise.

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Although I0I 03-1-01-1 has a few specific TS limitations for having

shutdown cooling inservice when in mode 2, it appears a specific

detailed procedure giving precautions, i.e., avoid pulling control rods

while cooling down, ete, would be necessary to perform this evolution

in the future. The licensee committed to prepare a comprehensive

procedure for placing shutdown cooling in effect when the plant is in

operational condition 2 with appropriate precautions and limitations by

February 2, 1986. This will'be Inspector Followup Item (416/85-46-02).

b .- IE Information Notice 85-94, Potential for loss of Minimum Flow Path

Leading to ECCS Pump Damage During a LOCA, was discussed with the

licensee. Although the review of IE Notice 85-94 is not complete the

Manager, Plant .0perations stated that any time the minimum - flow

provisions might not be available for the Emergency Core Cooling

Systems-(ECCS), the affected ECCS should be declared inoperable. Until

incorporated into plant procedures or position statements, this will be

Inspector Followup Item (416/85-46-03).

6. Maintenance Observation (62703)

During the report period, the inspector observed selected maintenance

activities: The observations included a review of the work documents for

adequacy, adherence to procedure, proper tagouts, adherence' to technical

specifications, radiological controls, observation of all or part of the

actual work and/or retesting in progress, specified. retest requirements, and

adherence to the appropriate quality controls.

One event occurred regarding the inadvertant starting of the Division 3

diesel generator. This event is discussed in Paragraph 9.d.

No violations or deviations were identified.

7. Surveillance Testing Observation (61726)

The inspector observed the performance of selected surveillances. The

observation included a review of the procedure for technical adequacy,

conformance to technical specifications, verification of test instrument

calibration, observation of all or part of the actual surveillances, removal

from service and return to service of the system or components affected, and

review of the data for acceptability based upon the acceptance criteria.

On January 10, 1986, the licensee identified two containment penetration

isolation valves, E61F009 and E61F010, which are used for containment purge

and which have not been local leak rate tested every 92 days as required.

TS 4.6.1.2.j states that purge supply and exhaust isolation valves with

resilient material seals shall be tested and demonstrated operable per

surveillance requirement 4.6.1.9.2. TS 4.6.1.9.2 states that at least once

per 92 days. each containment purge supply and exhaust isolation valve with

resilient material seals shall be demonstrated operable by verifying that

the measured leakage rate is less than or equal to 0.01 La when pressurized

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to Pa. Containment penetration 65 isolation valves E61F009 and F010 are

the suction valves for ~ the containment purge system. E61F009 and F010

were last local leak rate tested on October 11, 1984 but they were included

as boundary valves in the integrated leak rate test conducted during the

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October 11, 1985 thru December 7, 1985 outage. The licensee immediately

conducted a local leak rate test which the valves successfully passed. The

licensee has now included the above valves in their program to be local leak

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rate tested every 92 days. Failure to test the. valves as required is a

violation. The inspector's review determined that this matter met the

criteria of 10 CFR 2, Appendix C for licensee - identified violations and

therefore will not be cited.

No other violations or deviations were identified.

8. Reportable Occurrences (90712 & 92700)

The below listed event reports were reviewed to determine if the information

provided met the NRC reporting requirements. The determination included

adequacy of event description and corrective action taken or planned,

t existence of potential generic problems and the relative safety _ significance

of each event. Additional inplant reviews and discussions with plant

personnel as appropriate were conducted for the reports indicated by an

asterisk. The event reports were reviewed using the guidance of the general

policy and procedure for NRC enforcement' actions.

The_ foilowing License Event Reports (LERs) are closed.

LER No. Event Date Event

85-44' November- 18, 1985 Control Room Emergency

Filtration System-

Actuates on False

Chlorine Signal.

85-47 December 16, 1985 Control Room Emergency

Filtration System

Actuates on False

Chlorine Signal.

• 85-45 December 5,1985 Valve Limit _ Switches-

Found In Noncompliance

With 10 CFR 50.49

See Paragraph 10.d for a discussion of LER 85-45.

No violations or deviations were identified.

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9. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed reactor

events. The review included determination of cause, safety significance,

performance of personnel and systems,and corrective action. The inspectors

examined instrument recordings, computer printouts, operations journal

entries, scram . reports and had discussions with operations, maintenance and

engineering support personnel as appropriate.

During the period of December 30, 1985 - January 1, 1986, five events

occurred at the Grand Gulf Nuclear Station (GGNS) which resulted in major

reductions in power or challenges to safety systems. These events include

two trips of the recirculation pumps, two reactor scrams and an inadvertant

start of Division 3 Emergency Diesel Generator (EDG). The inspectors

reviewed each of these events and-a discussion of these events is provided.

below.

a. The first event which occurred at approximately 11:15 a.m. on

December 30, 1985, involved the inadvertant tripping of both recircula-

tion' pumps to the Low Frequency Motor Generator (LFMG) set. At the

time of the event, the plant was operating at approximately 100?J power

and Instrumentation and Control (I&C) technicians were performing

surveillance procedure 06-IC-IC34-M-0001. During the performance

of this surveillance procedure, the recirculation pump trip system

received a false low reactor water level trip signal which caused the

recirculation pumps to transfer to the LFMG set rapidly reducing

reactor power from 100?6 to approximately 55?;. This rapid reduction in

power caused vessel water level to increase to approximately 51 inches,

just below the high level scram trip, turbine trip and feed pump trip

setpoints. The licensee's investigation into the event involved

repeating the sequence of events which the I&C technicians performed

prior to the recirculation pump trip. This repeat of the I&C

technicians actions and the surveillance procedure failed to reproduce

the false low water level signal which caused the trip. The licensee

has been unable -to determine the cause of the recirculation pump

transfer to the LFMG Set.

During the review of this event, the inspectors discovered the licensee

had not performed any documentation of the occurrence. A review of

the plant requirements for documenting operating events revealed an

interpretation problem with the threshold used to determine when an

event should be written up and hence evaluated. The licensee agreed

that this event should have been documented and has committed to taking

the necessary actions to ensure that all significant events will be

documented. This will be identified as an Inspector Followup . Item

(416/85-46-04).

b. The second event which occurred at 7:15 p.m. on December 30, 1985,

involved the inadvertant tripping of B recirculation pump using the

Anticipated Transient Without a Scram (ATWS) trip function. At the

time of the event, the reactor was operating at 80?; power recovering

from the previous recirculation pump trip discussed above. I&C

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technicians were performing surveillance procedure 06-IC-1821-M-1012,

ATWS Reactor Vessel Level / Reactor Pressure Functional Test, when the B

recirculation pump tripped. This ATWS trip of B recirculation pump

caused reactor power to rapidly decrease to approximately 55*4 but the

plant was able to withstand the transient without shutting down

completely. The licensee's investigation into 'the event involved

. repeating the I&C technicians actions prior to the event but they were

unable to reproduce the inadvertant. ATWS trip signal. The cause of

this event as .well as the previous recirculation pump trip discussed

above remain undetermined by the licensee.

c. Scram No. 35. The third event involved a reactor scram from 100*4 power

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at 12:51 p.m. on December 31, 1985. Prior to the scram the plant had

been receiving low level alarms on the Intermediate Pressure (IP)

condenser hotwell but the control room level instrumentation indicated.

a level well above the low level setpoint. To ensure .that an actual

low level condition existed operations dispatched I&C technicians

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to the level instruments to fill and vent their reference legs.

Performance of the fill and vent procedure required the automatic

level control on the condenser hotwells to be placed in manual since.

the control signals come' from the level instruments. As the I&C

technicians were securing from the fill and vent procedure, the

condensate pumps tripped due to a low water level signal in the IP

condenser hotwell . This trip of the condensate pumps resulted in a

loss of feed to the vessel and a low level reactor scram.

It was determined later that an actual low level condition did exist

in the IP condenser hotwell. The combination of placing the hotwell

level controls in. manual and the performance of the fill and vent

procedure prior to filling the condenser hotwell to clear the low level

alarm caused the low level. trip of the condensate pumps.

Just after-the scram in response to the decreasing level in the vessel,

the - operator manually initiated both Reactor Core Isolation Cooling

(RCIC) and High Pressure Core Spray (HPCS). These two systems would

have automatically initiated if left alone oecause the vessel level

dropped well below their trip setpcint. During the manual initiation

of HPCS, the operator noticed that it was taking a long time for the

injection valve to open so he opened it manually. An investigation by

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the licensee determined that the HPCS injection valve failed to open

automatically due to a defective relay base. This defective base was

an Agastat relay type CR0009 base and problems associated with this

base were identified in a General Electric (GE) SIL No. 384 in October

1982 and a NRC IE Information ' Notice 82-48 in December 1982. The

licensee had taken the actions recommended by GE SIL NO. 384 in June

of 1983 and replaced all unsatisfactory relay bases on safety related

equipment. This particular base has now been replaced with a better

type and the injection valve was tested satisfactorily prior to

restart.

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d. The fourth event which occurred at 10:40 p.m. on December 31, 1985

involved the inadvertant starting of Division.3 Emergency Diesel

Generator (EDG). At the time of the event, plant personnel were

performing troubleshooting, under Maintenance Work Order (MWO) 58932,

to isolate the cause of the HPCS injection valve failure to open

automatically. The performance of troubleshooting involved _ lif ting

various leads by'I&C technicians to prevent automatic initiation of

the EDG while checking the operation of the injection valve circuits.

However, the technicians overlooked a seal-in relay which would give

the EDG a start signal. Since this relay was still in the circuit the

trouble shooting not only checked the automatic opening circuit for the

injection valve but also automatically initiated the Division 3 EDG.

The diesel generator was brought up to speed, loaded, run for 30

minutes and then secured as required. The trouble shooting was then

completed without further incident.

e. Scram No. 36. The fifth event which occurred at 9:12 a.m. on January

1, 1986 involved a reactor scram from less than 1% power during a

reactor startup. Reactor power was being monitored in the intermediate

range with pressure approximately 600 psig. The control room operator

received an annunicator indicating a high or low . vessel water level

condition. The level indication available to the operator consisted

of three level meters just above a level recorder. The operator only

looked at the level recorder and decided that the high low alarm was

due to a high level condition which was normal for this stage of the

startup. However, unknown to the operator, the level recorder had

stuck and the level meters indicated a decreasing water level. The

actual water level finally decreased to the low level scram satrient

and automatically scrammed the reactor. The operator not only missed

the decreasing water level but also failed to keep the feed pump

discharge pressure 100 psig above reactor pressure as required, which

prevented the feed pump from maintaining the vessel water level.

The root cause of this scram was the failure of the operator to monitor

all the required instrumentation available to ensure the reactor was

maintained in a stable condition. The failure of the operators to

monitor the three level meters installed above the level recorder was

also identified earlier in the post trip analysis associated with scram

number 21. Scram number 21, involved a malfunction of the switch used

to select the level instrument channel monitored by the feedwater

control system to maintain reactor vessel level. This switch failure

caused a decreasing water level signal to the feedwater control system

and the level recorder to indicate decreasing level. The operator

noticed the level recorder decreasing and feed pump flow increasing

to compensate for the level decrease but failed to monitor the three

level instruments above the recorder, which indicated actual level

was increasing- toward the high level scram setpoint. One of the

recommendations of the' post' trip analysis of scram number 21 was that

control room operators should compare recorder readings to indicator

readings often when monitoring reactor vessel water level. Administra-

tive Procedure (AP) 01-S-06-2, Conduct of Operations, step 6.3.6

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requires in part tha't one licensed operator be dedicated to monitoring

important parameters such as water level and pressure during a reactor

startup. Licensed operators are also trained to monitor all the

instrumentation available when monitoring a parameter. The failure of

the operator to monitor all the reactor vessel level instrumentation

during -startup and in response to a water level annunciator resulted

in an automatic scram and will be identified as a second example of

Violation (416/85-46-01). See also Paragraph 5.a.

-The operator also fai. led to monitor the feed pump discharge pressure

to ensure the feedwater pump was able to maintain vessel water level.

Integrated Operating Instruction (I0I) 03-1-01-1, Cold Shutdown to

Generator Carrying Minimum Load, step 6.2.14.b requires a . feedwater

pump be placed in service to maintain feedwater to the vessel and the

caution just below step 6.2.14.b requires the feedwater pump turbine

speed be increased as necessary to maintain feedwater pump discharge

pressure 100 psig above reactor pressure. The failure of the operator

to maintain feedwater pump discharge pressure 100 psig above reactor

pressure resulted in a reactor scram and will be identified as a-third

example of Violation (416/85-46-01).

The five events appear to indicate a decreasing trend in performance which

could be a precursor to more serious events. The inspector . discussed the

events and the inspector's concerns with the General Manager. The inspector

was told by the General Manager and the Site . Director that actions were

already being taken to address what they also considered to be an unaccept-

able trend. Corrective actions were. reviewed by the inspector and Region II

Management and were considered appropriate at this time.

10. Inspector Followup And Unresolved Items. (92701).

a. (Closed) IFI 416/85-20-03. The startup on December 22, 1985 as

discussed in paragraph 5.a of this report addresses the subject of

initiating shutdown cooling when in operational condition 2. This item

is closed.

b. (Closed) LIC 416/83-SC-01. This event was reported in LER 83-126. LER

83-126 was closed in IE Report 416/84-30. This item is closed.

c. (Closed) IFI 416/85-09-03. Step 8.3.1.1.4.1.d of the GGNS FSAR has

been revised to reflect the correct configuration in the plant relating

to the initiation logic for Division 1 and Division 2 diesel

generators. This item is closed.

d. (Closed) Unresolved Item (416/85-45-10). On December 2,1985, Grand

Gulf Nuclear Station (GGNS) maintenance personnel discovered several

environmentally qualified valves with limit switches that appeared to

be unqualified. The maintenance personnel documented their findings

an a Material Nonconformance Report (MNCR) and submitted this MNCR to

the Nuclear Plant Engineering (NPE) department for evaluation. On

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December 5,1985, NPE determined that some of the limit switches ~were

required to be qualified and were still evaluating the others. The

plant staff then notified - the NRC of the identification of these

unqualified limit switches. The plant was in cold shutdown at the

time of discovery of the unqualified limit switches. Walkdowns were

performed by plant staff of other environmentally qualified equipment

and no other discrepancies were discovered. The -licensee concluded

from the walkdowns that a generic breakdown of their Environmental

Qualification Program did not exist. The licensee also replaced or

otherwise qualified all of the suspected limit switches prior to

restart on December 7, 1985~.

Subsequent evaluations by NPE determined that of the 17 suspected limit

switches only 13 were required to be qualified. These 13 limit

switches only provided indication or inputs to computer points and

their failure could not affect the operation of their associated

valves. This item is closed.

e. (0 pen) Unresolved Item 416/85-45-01. By memo dated December 9,1985,

the plant requested Nuclear Plant Engineering (NPE) evaluate the low

flow for Standby Service Water (SSW) system B to certain electrical

switchgear room coolers. NPE was specifically asked if the rise in

temperature would be significant enough to cause a safety system

inoperability, a loss of a safety function, or in anyway significantly

compromise plant safety? NPE's response stated that the Material

Nonconformance Report (MNCR) reported low flow conditions on the B loop

of SSW and the . redundant A train coolers are available for cooling

their respective switchgear rooms. Also per Final Safety Analysis

Report (FSAR) Table 9.4-8, if a cooler loses its cooling capability

resulting in a loss of operation of electrical switchgear in that room,

the other ESF electrical switchgear located in other rooms is available

for operation. The plant then decided to check the flow capability of

the A SSW system to the electrical switchgear room coolers and found

that the A SSW system also experienced low flows.

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NPE was ver bally

requested to evaluate the additional information and by memo dated

December 20, 1985. NPE concluded that the effect of low SSW flow to

the _ electrical switchgear room coolers would not have resulted in the

rooms exceeding 140 F (which is the upper temperature limit for- the

safety related equipment located in the ESF switchgear rooms). This

evaluation took into account the fact that the ceiling of room 1A410

is the roof of the auxiliary building and during winter conditions

provides a large area for heat to be lost to the atmosphere. No

comment was made regarding the effect of operation in the heat of

summer. It appears NPE's original evaluation in response to the plants

December 9,1985 memo was very cursory in that no consideration was

given to the root cause of the B SSW ESF room coolers low flow (which

is the deposit of sand from the Plant Service Water (PSW) system that

supplies the ESF switchgear room coolers during normal operations) and

which did in fact cause low flow in the A SSW ESF room coolers. The

plant staff questioned the operability of the A SSW ESF room coolers

which caused them to test the A SSW loop and determine low flow was

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present there also. NPE's second evaluation also appears cursory in ,

that it did not address operability during warm weather'and failed to

address what actions would be necessary to continue operating with the

possibility of the ESF room coolers becoming stopped up again. No

mention of changing out room coolers, conducting periodic flow tests,

or other surveillance methods to ensure operability was discussed. The

licensee failed to recognize that FSAR paragraph 9.4.5.4 requires the

ESF room coolers be periodically inspected to ensure all normally

operating equipment is functioning properly and standby components are

periodically tested to ensure system operation. This last item was a

deviation in Report 416/85-45.

11'. Cold Weather Preparations (71714)

The licensee has initiated certain cold weather protection actions based on

past experience. The daily plant work schedule for December 13, 1985 listed

several cold weather action items, however the items listed on the work

schedule was not complete for all affected areas. The licensee's cold

weather preparations.are not procedurally defined nor~ are there any. cold

weather periodic maintenance requirements specified to ensure operability.

The resident inspector has discussed this with plant management and the

licensee has committed to prepare a comprehensive procedure, ' including

necessary periodic maintenance requirements, for cold weather preparations

by February 15, 1986. This will be an Inspector Followup Item

(416/85-46-05).