ML17229A407

inspectors

were thorough in their observations.

The containment inspections

were detailed in their scope.

Only minor

deficiencies

were noted.

Unit 2 Hi h Pressure

Safet

In 'ection

S stem Walkdowns

71707

On June 2-3,

a walkdown of both trains of the Unit 2 HPSI system

was

performed.

The inspection consisted of a'and

over hand walkdown of the

primary flow path of piping within the reactor auxiliary building as

well as

a walkdown of the main control

room panels.

The inspector

utilized the system operating procedure

as well as

P8ID 2998-8-078.

Sheet

130A.

The inspector also verified that the HPSI supply valves

from the

RWT were open.

There were some minor deficiencies not-

affecting operability noted

and referred to the licensee.

The overall condition of the system equipment

was good.

The inspector

noted that proper equipment oil levels were being maintained,

area

housekeeping

was acceptable

and no system leakage

was observed.,

In

02.4

02.5

addition,

as

a part of this inspection effort, the inspector

reviewed

portions of the Unit 2 Updated Final Safety Analysis Report

(UFSAR)

related to the HPSI system.

No discrepancies

associated

with the

UFSAR

were noted.

Low Oil Level in AFW Turbine

71707

During a plant tour. the inspector noted that bearing oil level for the

AFW pump

1C turbine was approximately

1 1/4-inches

below a mark on the

gauge glass casing.

This

mark was difficult to see

and the inspector

noted that the corresponding

gauge glass

for. the

2C AFW pump had two

marks which had been

enhanced with pencil to make these

more visible.

The vendor information stated

"Note filling marks

on the gauge glasses.

The oil level should not be allowed to drop below this level."

The inspector

questioned

two non-licensed

operators

regarding the proper

oil level

on

AFW pump

1C.

One was not sure

and the other stated that

about half way on the gauge glass

was acceptable.

The mark was at about

the two thirds height on the gauge glass.

The oil height was required

to assure

a slinger ring extends into the oil bath to provide oil to the

bearings

upon an initial pump start.

An oil pump was provided to supply

oil to the bearings

subsequent

to the initial start, therefore, this is

a long term bearing wear issue rather

than

a

pump operability issue.

Nevertheless,

this was considered

an example of poor field practices to

assure

desired oil level was maintained in the

AFW pump.

Periodic Test of the

En ineered Safet

Features

61726

Inspection

Scope

On Hay 18. the licensee

performed Engineered

Safety Features

(ESF)

testing in accordance with Procedure

OP 2-0400050,

Revision 23,

"Periodic Test of the Engineered

Safety Features."

The inspector

witnessed the pre-job brief and portions of'he performance of this

test.

Observations

and Findings

l

\\

The inspector attended

the pre-job.brief for this. surveillance

and noted

that it was attended

by all the test participants

and several

members of

licensee

management.

Following the brief, the plant was aligned to

support the test

and the participants

were individually briefed on the

specific tasks

each

was to perform;

The inspector witnessed the

performance of Sections

8.4 (A Train Loss of Offsite Power with

Integrated

Safeguards

(SIAS, CIAS, and

CSAS) Actuation Test with the

2AB

Buses Aligned to the A Side Electrical). 8.5

(2A.EDG 453

kW Load

Rejection

and SIAS/LOOP Swing Bus Testing with,.2AB Buses Aligned to A

Side Electrical);,and portions of 8.6 (Manual

A Train SIAS/CIAS/CSAS

Pushbutton 'Actuation Verification).

No abnormalities

were noted during

performance of these sections.

All systems

and components

responded

as

expected.

The inspector noted good communication

and coordination

among

the test participants.

03

03.1

This was

a reperformance of the failed April 15 surveillance.

Two

outstanding

issues

remain to be resolved.

During the April 15

surveillance,

the 2A1 Safety Injection Tank (SIT) Isolation valve failed

to open

on

a Safety Injection signal.

Engineering

has

been unable to

determine the cause of the failure.

The valve is only requi red to be

able to open if shut while in Mode 4.

The licensee

has revised its

operating

procedures

to open the

2A1 SIT isolation valve prior to

entering

Mode 5 while shutting

down and prior to exiting Mode 5 during

startup.

Engineering is:conducting further investigations to determine

the cause of the failure.

Another failure during the April 15 test involved the

2A Low Pressure

Safety Injection (LPSI)

Pump.

The pump started

as expected.

but then

tripped nine seconds later on thermal overload.

No mechanical

or

electrical

cause

was found.

The licensee

sent the motor to the vendor

for an evaluation,

but no cause

could be substantially

determined.

The inspector

found that the conduct of this surveillance at the end of

the outage (rather than at the beginning

as

had previously been the

practice)

met

TS surveillance

requirements.

The inspector further found

that the timing of the test

(immediately prior to post-outage

startup)

rovided an excellent opportunity to assess

the operational

readiness

of

ey safety systems

and components.

Additionally, the inspector

found

the licensee's

practice of performing this test one train at

a time

(rather than simultaneously

as

had been past practice)

enhanced

the

safety posture of the unit while the test

was being conducted.

As

performance of the test required creating losses of offsite power, the

single train methodology employed by the licensee

ensured that one train

of shutdown cooling was always operating.

Conclusions

This complicated surveillance

was completed satisfactorily and satisfied

Technical Specification requirements.

In performing the test at the end

of the outage.

the licensee

was able to establish

an excellent level of

confidence in equipment

readiness

prior to the upcoming fuel cycle.

The

performance of testing

one train at

a time was considered

a significant

safety enhancement

to the test methodology.

Operations

Procedures

and Documentation

Forei

n Material Exclusion

FME

Control of the Unit 2 Containment

Bui ldin

71707

a.

Inspection

Scope

The inspector

reviewed the

FHE controls associated

with control of

material

being used inside the Unit 2 containment building during the

refueling outage after the containment closeout

was complete.

This

inspection consisted of a review of'he

FHE log. discussions

with FHE

monitors,

and Quality Instruction QI 13-PR/PSL-2,

Revision 29,

"Housekeeping

and Cleanliness

Control Methods."

Observations

and Findings

At the end of the Unit 2 refueling outage,

the containment bui'lding was

controlled

as

an

FME area.

On Nay 23,

1997. the inspector

reviewed the

- FME log book associated

with the containment building.

Inside the book

were instructions which stated that "With the exception of maintenance

personnel

working on the Reactor Drain Tank/Containment

Sump Project all

other personnel

shall complete the

FME log.

Health Physics personnel

(later changed to Security) shall

man the

FHE log desk

and ensure that

the log is completed for personnel

entering

and exiting the

RCB.

Maintenance

personnel

working on the Reactor Drain Tank/Containment

Sump

Project are not required to comply with the

FME log requi rements

since

a

FME walk down of the work area will be performed at the completion of

the project."

Also in the log book, were log sheets

indicating the

material that was taken into and out of containment.

On May 29, after the containment

was closed out and the

FME area

released,

the inspector

reviewed these

log sheets

and noted several

items that had not been

logged

as having been

removed from the

containment.

These items included;

paper,

safety belt, paperwork,

pen.

tape, bolts. radio with ear muffs," rubber suit, flashing light.

clearance

tags,

miscellaneous

hand tools, pipe wrench. five flashlights.

crescent

wrench,

one bottle of snoop.

and

a gauge.

In addition,

nineteen individuals signing in on the log failed to sign out upon

exiting.

The inspector

discussed

the instructions listed in the

FNE log with

various licensee

management

stating that these instructions did not

agree with the site procedure

for control of FHE.

The licensee stated

that it was not their intention to maintain the containment

as

an

FHE

area

as defined in the.QI.

Their philosophy was that after the sump

work was complete the entire area would be inspected

and any remaining

items would then

be removed.

Therefore it was not necessary

to log all

items entering into this particular

area.

However, they did require

that personnel

not working on the sump job complete the

FNE log.

The

inspector noted that the entrance to the containment

was identified as

an

FNE area,

that an

FHE log was established

to control material

entering

and exiting the area,

and that an

FHE monitor was established.

Procedure

QI 13-PR/PSL-2,

Section 5.5. stated,

in part, that foi Quality

Group

B systems

and components, "if an

FNE Control. Area is required.

the

control area

and controls-shall

be established.prio'r

to opening the

system or component.

FME controls in accordance

with this procedure

'hall

be established,

as -needed,'o

maintain the cleanliness

requirements.-

Appendix

B provides guidance

on the methods of

controlling foreign. material."

Section 7.6, "Definitions,." states that

Quality Group

B applies to the containment vessel.

Appendix 8 of this

QI states

in part that

"FHE control areas.

as defined by QI 13-PR/PSL-2,

are used in those situations

where it is not feasible/practical

to

install

an

FHE control device to prevent loss of foreign material into a

system/component.

Tools/materials

which are taken into FME control

7

areas

are logged for accountability."

In addition, Section 5.15,

"General

Housekeeping,"

step 11.A, states that,

"Material accountability

shall

be applied when misplaced tools equipment,

and other materials

could be detrimental to the plant item involved.

When material

accountability is applied. tools and other materials shall

be logged

into and out of the area."

The inspector

reviewed the site procedures f'r guidance

on when

a

FHE

monitor was required and:what training was required prior to assuming

that position.

QI 13-PR/PSL-2 stated that

FHE monitors

may be used at

the discretion of the Plant Management,

to control the area

around the

reactor cavity when the reactor vessel

head

was

removed

and in the fuel

handling building when work was taking place around the spent fuel pool.

With regard to training, Appendix A. step

1, states that the reactor

cavity monitor should receive orientation

as to the refueling process,

the reactor coolant system

and this QI.

The QI made

no mention

concerning

FME monitors for other areas

or

any associated

training.

10 CFR 50, Appendix B, Criterion

V requires that activities affecting

quality shall

be prescribed

by documented

procedures

of a type

appropriate to the circumstances

and shall

be accomplished

in accordance

with these

procedure.

Procedure

QI 13-PR/PSL-2 is the procedure that

implements this requirement

with regard to foreign material control.

Failure to adequately control the material entering

and exiting the Unit

2 containment is

a violation of this procedure

and is identified as

50-389/97-05-01.

"Failure to Control Foreign Material Entering and

Exiting the Unit 2 Containment.."

Conclusions

The inspector concluded that the licensee's

implementation of the

FME

program at the entrance to the Unit 2 containment

as the unit approached

.post-outage

startup

was insufficient to satisfy procedural

requirements.

A violation for failing to follow the governing procedure

was

identified.

04.1

Operator

Knowledge 'and Performance

Monitorin of Control

Room Instrumentation

71707

Inspection

Scope

The inspector walked down the Unit 2 control. room instrumentation to

verify proper operation

and to verify operator

awareness

of those

instruments

not functioning properly.

't

Observations.

and Findings

'I

On Hay 24, the inspector walked down the control panels in the main

control

room paying particular attention to instrumentation that

appeared to be indicating erroneous

values or operating incorrectly.

During the outage

many of these

instruments

had been out of service for

maintenance.

At this time the plant was in the process of being aligned

for startup.

The inspector

noted three flow recorders

not indicating

roper values

and three recorders that were not inking as indicated

elow:

~

FR 3323

- HPSI Loop 2A2 8 2A1 flow indicating 90 gpm with the

system out of service.

~

FR 3306 - Shutdown Cooling 2A Loop flow indicating 500

gpm with

the system out of service.

~

FR 3301 - Shutdown Cooling 2B Loop flow indicating 1000

gpm with

the system out of ser vice.

The recorder

was also not inking.

~

PR-07-4B/5B - Containment

and

Sump pressure

had one of two pens

not inking.

~

LR 12-11B - Condensate

Storage

Tank level was not inking

The inspector

questioned

the operators

because

none of these

instruments

had work requests

(WRs) written to have them repaired.

The inspector

requested

that the chart paper

be unrolled to determine

how long these

conditions existed.

It was noted that in all cases

the conditions

had

existed for at least two days without any action having been taken by

Operations.

WRs were written for the instruments with erroneous

indications.

The operator

on shift adjusted the recorders

not inking

until they inked properly.

On June 3, the inspector

again walked down

the control panels

and noted two additional recorders

not inking as

indicated below:

~

LR-12-11B - Condensate

Storage

Tank level again not inking

~

PR-08-1/2 - 2A and

2B SG Outlet/Turbine Inlet pressure

had only

one of three

pens inking.

Again. the inspector

noted that .these, problems .had been. occurri.ng for at

least two days without action being taken.

This was brought to the

attention of the control

room staff and licensee

management.

1

The inspector

reviewed Procedure

OP-2-.0010125,

Revision 10,

"Schedule

Of

Periodic Tests,

Checks

and Calibrations,"

and noted that step

21

required that control

room chart recorders

be checked

each midnight

shift for, proper timing ..and to verify the chart paper

was not low.

In

addition, the step required that the recorders

be stamped.

Although the

procedure

does not explicitly state that the recorders

are-to

be

verified to be operating properly, a'discussion

with several

operators

indicated that was the intent.-

After this was brought to the attention of management,

the instruments

were promptly repaired.

08

08.1

Conclusions

The inspector

considered

the large number of instrument

problems

identified to be

a weakness

in operator attention to the main control

panels.

The 'acceptance

of broken instrumentation

on the main control

panels

by the operators,

particularly following a refueling outage,

indicates

a willingness to accept

inadequate

equipment

performance.

Hiscellaneous

OperationsIssues

Closed

VIO 50-335 389/96-01-01

"Tem orar

Chan

es to Procedures

Im ro erl

Chan

ed Intent of Procedures"

92901

Inspection

Scope

This violation (VIO) involved a failure of the licensee's

Facility

Review Group

(FRG) and the Plant General

Hanager

(PGH) to review and

approve temporary changes

(TCs) to procedures,

which involved a change

of intent, prior to implementation.

This inspection effort focused

on

the licensee's

corrective actions specified in the response to this VIO

and review of other related documentation.

Observations

and Findings

The inspector

reviewed the corrective actions specified in the

licensee's

response to this VIO for compliance with the Technical

Specifications

(TS) and applicable licensee

procedures.

The inspector

reviewed the

FRG meeting minutes for the TCs listed in the subject

and verified that the TCs had been

reviewed by the

FRG and approved

by

the

PGH.

The inspector also reviewed Administrative Pro'cedure

(ADH)

ADH-11.03, Revision 0,

"Temporary Changes to Procedures."

This

procedure

had been previously issued

as Administrative Procedure

0010148.

Procedure

ADH-11.03 had been revised to provide additional

guidelines

regarding what TCs to procedures

could be considered

as

changing the intent of a procedure.,

In addition, the procedure

had been

revised to include expanded

change of intent guidelines

and prior

approval

requirements

for TCs. .If a..TC was determined..to

involve a

change of intent.,to

a procedure the,.change

was..then

required to,be

processed

as

a normal procedure

change

request rather than

a TC.

The inspector

reviewed

some

TCs which had been

implemented in 1997 in

order to verify that the TCs had been -implemented in accordance

with

Procedure

ADH-11.03..

During review of these

TCs, the inspector

did not

identify any examples

where the

TC involved a change of intent to the

applicable procedure.

During further review of these

TCs. the inspector

made the following observations

which indicated that additional

clarifications to Procedure

ADH-11.03 may be warranted.

~

During review of TC 1-97-044, the inspector noted that the author

of the

TC performed the 50.59 screening

as the qualified reviewer

and also signed

as the first member of the plant management staff

to indicate one of the two approvals

required for the TC.,

4

10

Procedure

ADM-11.03 stated that the

TC author

was responsible for

obtaining the review and signature

approval of the

TC from two

members of the plant management staff prior to implementation.

Although Procedure

ADM-11.03 does not specifically prohibit the

TC

author from performing the 50.59 screening

and also being one of

the two approvers of a TC, the inspector questioned

whether this

TC met the intent of Procedure

ADM-11.03 with regard to

incorporating adequate

independence

in the review process relative

to this TC.

The inspector also questioned

the licensee's

definition for

a

"member of plant management staff" with regard to employees

who

could approve

TCs.

Procedure

ADM-11.03 defined

a member of plant

management staff as

a permanent

Florida Power and Light Company

(FPL) employee

who was functioning at the Plant St. Lucie (PSL)

site in a supervisory capacity.

Examples given in Procedure

ADM-

11.03 for

FPL employees

meeting this definition were

foreman/reactor

control operator

(RCO) and above for bargaining

unit employees,

and senior plant technician

and above for non-

bargaining unit employees.

The inspector

noted that

some of these

examples

given in Procedure

ADM-11.03 were not consistent with the

licensee's

organizational

chart with regard to employees

functioning in a supervisory capacity.

For

example,

the author of

TC 1-97-044

was

a system engineer.

As stated

above, this system

engineer

also signed

as the first member of plant management staff

to indicate one of the

TC approvals.

However, this system

engineer

was not listed in a designated

supervisory position on

the licensee's

organizational

chart.

The inspector also questioned

whether

adequate training had been

provided to all the employees

(included under the licensee's

examples

as

members of plant management staff) with regard to the

review and approval of TCs.

The inspector noted that there were

training requirements

specified for the qualified reviewer and the

- second

member of the plant management staff'ho could approve

a

TC

was required to hold a Senior Reactor, Operator 's

(SRO) license

on

the unit-affected.

There were no specific training requirements

for the first member of the plant management staff who could

approve

a.TC.

During review of TC 1-97-053, the inspector

noted that the

TC was

approved

by only one member from the plant management staff

instead of two members,

as required by, Procedure

ADM 11.03 and the

TS for both units.

During further'review

and discussion of this

TC with licensee

personnel,

the inspector

noted that the licensee

had identified this issue prior to this inspection

and

had issued

condition report

(CR) 97-1060:,

The inspector further noted during

review of-a licensee .Quality Assurance

(QA)- Audit Report

(QSL-DOC-

97-04), that

QA had identified two TCs that contained 'only the

signature of the nuclear plait supervisor

(NPS) indicating plant

'anagement

staff approval.

V

C'

~

During review of TC 1-97-054, the inspector noted that an

individual other than the

TC author

completed Part A of the

Temporary

Change Checklist (Appendix

B of Procedure

ADM-11.03).

Step

6. 1. 1.B of Procedure

ADM-11.03 and Part

A of the Temporary

Change Checklist both stated that Part A was to be completed

by

the

TC Author.

The inspector noted that these steps

were

inconsistent with Step 3.4.2 which stated that the

TC Author or

person

assigned

the responsibility for the TC complete Part A of

the Temporary

Change Checklist.

~

The inspector noted several

examples

where the TC request

form

indicated that

a procedure

on the other unit was affected by the

TC.

There did not appear to be

a clear tracking mechanism to

ensure that the procedure

on the other was changed.

The inspector

discussed this item with licensee

personnel

who indicated that the

document proofreading guidelines provided another

opportunity to

remind personnel

to address

the affected procedures

on the other

unit.

The inspector discussed

these observations

with licensee

management

who

indicated that Procedure

ADM-11.03 would be reviewed to determine if any

additional

changes

or clarifications were needed.

The inspector stated

that licensee

actions to address

the above observations

regarding the

TC

process will be tracked

as Inspector Followup Item (IFI) 50-335.389/97-

05-02,

"Licensee

Review and Clarification of Procedure

(ADM-11.03) for

Performing Temporary Changes to Procedures."

Violation 50-335,389/96-

01-01 will be closed.

c.

Conclusions

The inspector concluded that the licensee

had taken adequate

cor rective

actions to address

VIO 50-335,389/96-01-01.

This VIO will be closed.

The inspector

concluded

from the review of some

TCs which had been

implemented in 1997 that additional clarifications to Procedure

ADM-

11.03, with regard to implementation of the

TC process,

may be

warranted.

A new inspector

followup item was identified to review the

licensee's

actions to address

the inspector's

observations

with regard

to the clarification of Procedure

ADM-11.03.

08.2

Closed

LER 50-335/95-003

"Automatic Reactor

Tri

Durin

Turbine.

.

Overs

eed Surveillance Testin

Due to Personnel

Error"

92901

On July 8.

1995, a'eactor trip occurred

due to high pressurizer

pressure

when

a valving error

occurred during main turbine overspeed

testing.

The procedure

being used,

OP 2-0030150.

"Secondary Plant

Operating

Checks

and Tests,"

required that the Overspeed

Protection

Control

(OPC) solenoid valve be isolated from the test header by-closing

a manual

valve.

The non-licensed

operator

removed the, locking device

from,-the valve, but got-distracted,

and failed to close it:

Subsequently,

the governor

and intercept valves closed which ultimately

resulted in the reactor trip.

08.3

12

Corrective actions for this event included counselling the involved

individual, revising the procedure to include additional verification

for critical steps.

reviewing the event with other operators

during

formal training,

and reviewing other load threatening surveillances to

ensure

adequate

precautions to prevent personnel

error are present.

The

inspector

reviewed the current revision of the aforementioned

procedure,

Revision 85,

and noted that the appropriate

revisions

had been

made.

Additionally, other portions of the procedure

were also reviewed

and

were also noted to have been revised to add additional verifications to

critical steps.

This

LER is closed.

Closed

LER 50-335/95-009

"Missed Technical

S ecification Scheduled

Surveillance

Oue to Personnel

Error"

92901

This surveillance

was missed

on October

20,

1995,

when the licensed

operator initialed the Technical Specification tracking sheet prior to

performing the required surveillance.

The surveillance

was

a

verification of Control Element Assembly

(CEA) position indication by

comparing the reed switch position indication and pulse counting

position indication.

A form,

known as the

CEA log. listed each

CEA and

provided two blanks to record the position from the two aforementioned

methods.

Upon completion of the

CEA log, the operator

then was to

initial the check sheet signifying the surveillance

was completed.

On

this date,

the check sheet

was initialed but the

CEA log sheet

was not

completed.

Corrective actions included performing the surveillance,

counselling the

involved individual. issuing

a

memo to operators reiterating plant

policy regarding

documentation of work activities,

and referencing the

CEA log sheet in the surveillance

check sheet.

Since this event

occurred,

the surveillance

check sheet

procedure

has

changed.

The check

sheet is currently

a section of Procedure

OP 2-0010125.

Revision 9,

"Schedule of Periodic Tests,

Checks,

and Calibrations."

The inspector

reviewed this procedure

and verified that the

CEA log was referenced in

this procedure.

'This

LER is closed.

Closed

LER 50-389/97-001

"Containment Isolation Actuation Due to

Increased

Radiation Levels Ourin

Removal of U

er

Guide Structure"

.

~92901

The details of this event were previously discussed

in Inspection Report

97-04.

The inspector

has since reviewed the

LER and verified the

corrective actions were appropriate.

Com an

Nuclear

Review Board

CNRB

71707

The inspector

attended

a portion of CNRB meeting

No. 443 held at St.

Lucie on.May 20.

-The inspector verified that the meeting

was conducted

in accordance with Technical Specification 6.5.2.

Generally, the

CNRB

meets monthly, rotating the location of the meeting

among the three

FPL

sites (e.g.,

Turkey Point. St. Lucie

and Juno Beach).

Representatives

from all three locations are present at each meeting.

'3

The inspector noted that the St. Lucie Plant Manager's

report was very

informative and it sparked

a good exchange of questions

and

a healthy

discussion.

The inspector also noted that the

CNRB addressed

self-

assessment

issues

and held

a discussion of early warning indicators in

order to identify degrading

performance.

The inspector

concluded that

the

CNRB remained

focused towards nuclear

safety, effectively carried,

out their charter,

and that members displayed

a very good questioning

attitude.

II. Maintenance

Hl

Conduct of Maintenance

Ml.1

General

Comments

61726 62707

a.

Inspection

Scope

Using inspection procedures

61726 and 62707, the inspector

obser ved

portions of the f'ollowing activities:

~

Work Order

(WO) 97005642-01,

Calibration of AFW Flow Loop FT-09-

2Al:

Procedure

2-1400064F,

Revision 38, "Installed Plant

Instrument Calibration (Flow)."

Note:

Personnel

identified a

leak in the equalization valve and. therefore.

were unable to

complete the calibration.

~

WO 96031227,

18 Month Preventive

Maintenance

Inspection of Valve

HV-09-11 (1C AFW Pump to 1A Steam Generator);

Procedure

940072.

Revision 14, "Preventive Maintenance of Environmentally Qualified

Limitorque Motor Operated

Valve Actuators."

~

WO 3200, Torque Switch Preventive

Maintenance for Valve HV-09-11;

Procedure

80.01, .Revision 0, "Limitorque Model SHB-000 Torque

Switch Preventive Maintenance."

~

WO 97002052-01,

18 Month Preventive

Maintenance

Inspection of

Valve HV-08-3 (1C AFW Trip and Throttle Valve): 'rocedure

0940069,

Revision

18, "Preventive Maintenance of Non-

Environmentally Qualified Limitorque Motor Operated

Valve

Actuators."

The inspector also observed portions of post maintenance testing of

valves associated

with the

1C AFW pump.

b.

Observations

and Findings

Personnel

were knowledgeable

and performed in accordance

with procedural

requirements.

Good material

support

and management

oversight

was noted.

A thorough inspection of wiring on Valve MV-08-3 identified wiring

damage which was carefully repaired.

Also, wiring was rebundled to ease

installation of the limit switch cover.

One example of poor work

planning was noted.

Valve MV-08-3 was initially stroke time tempted

Hl.2

a.

'4

resulting in also running the

1C AFW pump.

Subsequently,

maintenance

personnel

informed Operations that the valve operation

had to be

verified at all remote locations in accordance with a general

step in

the procedure.

Operations

was not aware of the requirement

and an

additional

unnecessary

pump run resulted.

Also, no specific procedural

steps

were provided for the testing.

Operators

had to energize the

remote shutdown panel

using

a Deviation Log.

Licensee Administrative

Procedure

0010120.

Revision 91,

"Conduct of Operations."

does allow

routine tasks to be performed without specific procedures.

however. this

testing could have been conducted better if'ore specific guidance

had

been provided.

In addition, preplanning activities such

as the pre-

evolution briefing failed to identify the testing requirement.

The

licensee

indicated that

a post briefing had identified similar

weaknesses'onclusions

Personnel*performed

well and carefully followed procedures.

However,

one example of poor planning

and poor procedural

guidance

was noted for

post maintenance testing of the

1C AFW trip and throttle valve.

Pressure

Lockin

Hodifications to Unit 2 Shutdown Coolin

Isolation

Valves

62707

37551

Inspection

Scope

The inspector

reviewed the plant modification package.

PC/H 96138.

"Drilling of Valve Disk for V3651,

V3652,

and V3480," and observed

some

of the maintenance activity associated

with the modification.

Obser vations

and Findings

This Plant Change/Hodification

(PC/H) package provided for the

modification of Unit 2 SDC isolation valves

V3651,

V3652,

and V3480

located in containment

on the hot leg suction lines to the

2A and 28

LPSI pumps.

The licensee's

intent was to satisfy commitments associated

with Generic Letter 95-07,

"Pressure

Locking and Thermal Binding of

Safety-Related

Power-Operated

Gate Valves."

The modification consisted

of drilling a 3/16 inch hole in'the upstream

(reactor coolant) side of

the valve disk to vent the bonnet of high pressure fluid.

This would

revent the conditions that allow pressure

locking to occur.

The

icensee

previously performed this modification on another Unit 2 valve,

and this modification was endorsed

in NUREG-1275,

Volume 9,

"Operating

Experience

Feedback

Report

- Pressure

Locking and Thermal Binding of

Gate Valves."

The inspector

reviewed the

PC/H package

and noted that it was clearly

written, the 50.59 screening

was appropriately performed.

and all

reviews

and approvals

were timely.

The individuals performing the

approvals

and reviews were appropriate.

The package

clear ly'dentified

the. work instructions

and al.l post-modification testing required.

I

'5

The work was performed after all fuel had been

removed from the reactor

vessel.

Freeze

seals

were installed to isolate the hot leg piping to

allow draining.

The inspector observed portions of valve V3480

disassembly,

and valve V3652 reassembly.

Maintenance

personnel

were

knowledgeable

about the job, appropriate

reference material

was at the

job site,

QC oversight

was appropriate,

and all Measuring

and Test

Equipment

was properly checked out and calibrated.

Two problems occurred during reassembly of the first valve worked, valve

V3480.

When the crew initially was installing the valve yoke, they

determined that the stem was rotated

180 degrees

from the requi red

position.

Although the valve was symmetrically similar, it was not

exact.

Inattention to detail

by the maintenance

crew allowed them to

install the stem backwards.

The valve was disassembled

again.

verified that the gasket,

valve seat,

and valve body were not damaged.

The valve was subsequently

reassembled.

The second

problem occurred during the retorquing of the bonnet.

After

satisfactorily completing the final torque sequence.

the licensee

performed the required post-work calibration check of'he wrench.

The

calibration check

was unsatisfactory.

Condition Report 97-0918

was

issued to document the deficiency and the bonnet

was later retorqued

satisfactorily.

The inspector

judged the overall quality of the maintenance

work to be

good.

The maintenance

workers were familiar with the work procedures.

Reference material

was in the work area.

Radiological control practices

were noted to be good.

Quality Control verifications were performed

as

required,

and problems were raised to the appropriate levels of

management.

Conclusions

The inspector

judged the overall preparation

and conduct of the

modification to the

SDC valve disks to be good.

The

PC/M package

was

prepared appropriately

and conduct of the work was good.

Installation of Unit 1'DDPS Constants

62703

92902

Inspection

Scope

The inspector

reviewed

WO 97004867 which documented the revision of

(FW) flow constants

in DDPS,

This activity occurred in

February.

1997.

In addition, the inspector

reviewed ADM-0010432,

Revision 11, "Control of Plant Work Orders" to determine if the

WO was

in compliance with the controlling administrative procedure.

Observations

and Findings

The. purpose of WO 97004867,

as stated in the package,

was to allow

testing of the

DDPS to verify calorimetric equation for FW flow, and

', 16

verify inputs

as necessary.

The work instructions contained the

following steps:

"1)

At System Supervisor discretion obtain clearance

or permission to

lift/land leads

8 manipulate local valves

and document the

Independent Verification sheets of ADH-0010432 (Fig. g4).

2)

Hook up test equipment

as determined

necessary

by supervisor to

allow measurement

of FW flow inputs

and verify calorimetric

equation for FW flow.

Perform tests

as determined

by supervisor.

3)

Hake adjustments if necessary

at discretion of, supervisor.

4)

Remove all test equipment

when work complete.

5)

If required troubleshoot/repair

associated

loop components

as

directed

by supervisor

using manufacture

tech manuals

as

references,

as necessary.

6)

Document all work performed

and parts replaced

on the journeymans

work report."

The

WO basically relied on the super visor to determine the actions

necessary

to complete the objective of the

WO.

ADH-0010432, Revision,

ll, "Control of Plant Work Orders" step 7.1. 1 stated,

in part, that

plant work activities which can affect the performance of guality

components.

structures,

and equipment shall

be

appropriately planned

and performed in accordance

with written

procedures,

documented

instructions

and approved

drawings to ensure the

equipment

meets its design function.

In addition, step 7.3.2.D states,

in part, that "if a work task is particularly complicated,

involved many

steps to complete,

involves complex operations

which must be completed

in. a specific order, or has other, demanding

requirements (i.e.,

beyond

the skill of the craft). then sufficient details to accomplish the task

must be provided in NPWO."

The planner

may use any of the following:

~

Plant procedures

(specific sections

or the entire procedure)

~

Maintenance Guidelines

.

~

Reuse Specifications

~

Specific step-by-step

work instructions

~

Technical

Manual step-by-step

work instructions

I

0

Conclusions

17

M1.4

M1.5

The inspector concluded that completion of this

WO involved many

particu1ar ly complicated

steps involving complex operations with a

Ouality Related

component without providing one of the approved

methods

as delineated

in ADM-0010432.

10 CFR 50 Appendix

B Criterion V.

requi res, in part, that activities affecting quality shall

be prescribed

by documented instructions,

procedures,

or drawings. of a type

appropriate to the ci rcumstances

and shall

be accomplished

in accordance

with these instructions,

processes.

or drawings.

ADM-0010432, is the

licensee

procedure that implements this requirement

with regard to

maintenance

planning.

Failure to provide adequate

work instructions for

the performance of WO 97004867 is

a violation of this procedure

and was

identified as

VIO 50-335/97-05-03,

"Failure to Provide Adequate

Work

Instructions

For a Work Order."

AFW Valve Testin

62707

Inspection

Scope

. The inspector

observed portions of perf'ormance of Operating

Procedure

OP-2-0010125A,

Revision ll, "Surveillance Data Sheet

24 Valve Testing

Procedures."

Observations

and Findings

On May 20, the inspector

observed the valve stroking of Unit 2 vacuum

relief valves

FCV-25-7 and FCV-25-8.

The procedure

steps

required

coordination

between operations

and instrumentation

and control

personnel

and included independent verification.

The personnel

performing the procedure

were knowledgeable

and familiar with the

required steps.

It was noted that although the terminals to be jumpered

for each valve were distinctly identified. the operator further verified

the listed terminals using the control wiring. diagram number 529.

Conclusions

The inspector concluded that referencing the control wiring diagram was

a good practice.

The independent verification steps

were performed

correctly and Data Sheet

24 performance

was acceptable.

1

Auxiliar

Feedwater

Ter r

Turbine Post Maintenance Activities

62707

Inspection

Scope

The inspector

observed

several

post maintenance activities on 2C

Auxiliary Feedwater Turbine.

The placement

and removal of clearance

number

2-97-05 was observed

as well as performance of the following

procedures:

~

.

2-0700028.

Revision 7, "Auxiliary Feedwater Turbine Mechanical

And

Electrical Trip Tests"

0

18

~

2-M-0109, Revision 7,

"2C Auxiliary Feedwater Terry Turbine

Disassembly,

Inspection,

and Reassembly"

~

2-0700050,

Revision 4, "Auxiliary Feedpump Periodic Tests"

~

2-IMP-0901, Revision 3,

"2C Auxiliary Feedwater.

Pump Governor Oil

Change Instruction"

The

WOs reviewed f'r completeness

and applicability included:

~

WO 96022182,

"2C Auxiliary Feedwater

Pump Overspeed

Task"

~

WO 96019379,

"Turbine Drive for Auxiliary Feedwater

Pump 2C"

~

WO post-maintenance

test for 97002292,

"Repack Valve V9103"

b.

Observations

And Findings

On May 21,

1997, the inspector observed

several

post-maintenance

activities on the

2C Auxiliary Feedwater

Pump.

The electrical trip test

was performed while the

pump was uncoupled

from the turbine and

completed without complications.

As part of the test.

the mechanical

~

trip set point is raised to a value greater

than the electrical trip

setpoint to ensure the

pump trips on the electrical

and not the

mechanical trip. It was noted that the Instrumentation

and Control

(18C) technicians

used additional

references

along with the test

procedure to verify the mechanical trip setpoint

was correct when the

tripset point was returned to normal status.

After the electrical trip test,

maintenance

personnel

coupled the

pump

to the turbine by replacing the spool piece per

2-M-0109.

To allow the

spool piece replacement.

operations

personnel

placed clearance

2-97-05.

The clearance

was placed,

the independent verification was performed.

and

a third managerial

verification was completed prior to the spool

piece replacement.

The pump spool piece

was verified to be correctly

positioned using the match marks

and the alignment

was completed without

incident.

When removing clearance

2-97-05. the trip and throttle valve

control switch was to be returned to the locked open position.

However,

the valve was not latched correctly;.therefore,

when the control switch

was placed in the open position the valve indication was intermediate

rather than open.

A nuclear plant operator relatched-the

valve and the

remainder of the clearance

was

removed without incident.

After being coupled,

2C feedwater

pump was rolled in preparation for the

governor oil replacement activity.

The inspector noted that the pre-job

brief was very detailed.

While waiting for the

pump to be rolled. the

inspector

observed

an. IKC technician; walking through the governor oil

replacement

procedure prior to performance to ensure familiarity with

the procedure.

While. the

pump was,being rolled, the post maintenance

test for valve V9103 was completed

by the nuclear plant operator.

4

Conclusions

'9

4

M4

M4. 1

The inspector

concluded that, in general,

the activities were performed

adequately.

The procedure

performance

was acceptable

and the calibrated

equipment

was

up to date.

All activities were performed in a

professional

and competent

manner.

In particular, the

18C technicians

exhibited good working practices

by using additional

references

for

setpoint verification and walking down procedures

prior to performance.

Maintenance Staff Knowledge and Performance

Unit 2 Main Steam Isolation Valve Maintenance

MSIV

62707

Inspection

Scope

The inspector witnessed portions of the maintenance activities

associated

with the Unit 2 MSIV, HCV-08-1B.

The work was being

performed in accordance with WO 95035292.

Observations

and Findings

Throughout the refueling outage the inspectors

witnessed portions of the

maintenance activities associated

with the rebuild of the 08-1B MSIV.

On May 15. the inspector witnessed the valve bonnet bolts being torqued.

The

WO required several

passes

of increasing torque until

a final value

of 3300 ft-lbs was obtained.

Maintenance

was using

a hydraulic torque

wrench to tighten the nuts which was attached

by hoses to an oil sump.

The torque value applied to the nuts

was increased

as the operating oil

pressure

being supplied to the wrench was increased.

A gauge

was

mounted

on the oil sump to indicate the operating oil pressure.

The

inspector

reviewed the

WO and noted that, although the bonnet nuts were

still being tightened,

the final torquing step

was already signed

by

personnel

from both the licensee

and the valve contractor.

The

inspector questioned the

QC individual working for the contr.actor and

was told that after the nuts were torqued to the final value of 3300 ft-

lbs, the wrench being used

was checked for calibration.

During

calibration. the contractor

QC individual noted that the operating oil

ressure,

indicated

on the gauge,

was not equal to the torque value

eing applied by the wrench. i.e.,

an indication of 100 psi operating

oil pressure

did not equal

100 ft-lbs of torque supplied

by the wrench.

However. this had been his understanding

up to that point, which

resulted in the bonnet nuts being undertorqued.

Upon discovery..the

bonnet nuts were torqued to the proper value and verified by both

contractor

and licensee

QC inspectors.

The inspector obtained the names.

through tool usage logs, of other

individuals who had used this type of tool to determine if this

misconception

was generic in nature.

Three people were interviewed and

all had

a complete understanding of the difference between operating oil

pressure

and applied torque.

In addition. the problem was discussed

with the

QC supervisor

and the

QA manager.

The licensee

questioned all

personnel

who had used these tools and confirmed that no

'0

misunderstanding

existed with regard to this problem.

In addition, the

inspector verified that the "Restricted

use" sticker was affixed to the

tool being used

on the job site and that it had the proper conversions

between operating oil pressure

and applied torque.

Conclusions

The inspector concluded that although there

was confusion about

how to

determine proper torque values with the hydraulic wrench. the nuts were

not overtorqued,

the problem was identified by the maintenance

process

as intended,

and the proper torque was later applied to the bonnet nuts.

Licensee

and inspector review determined that this was

an isolated

problem associated

with this job only.

Post Maintenance Testin

of the Reactor Coolant

Gas Vent

S stem

RCGVS

~62707

Inspection

Scope

The inspector

witnessed portions of the performance of Procedure

2-OSP-

01.02,

Revision 2,

"Reactor

Coolant

Gas Pent

System Flow Path

Verification." and reviewed the entire procedure

upon completion.

Observations

and Findings

On May 15. the inspector witnessed portions of the performance of

Operations Surveillance

Procedure

2-0SP-01.02,

Revision 2, "Reactor

Coolant

Gas Vent System Flow Path Verification."

This procedure

verifies that the

RCGVS is free of obstructions

by flushing water

through the pipin'g.

This. system

was to be flushed in three sections.

The inspector verified that the flowpath and overlap of'ach section

was

adequate to ensure the entire system

had been flushed.

The

instrumentation

used

was adequate for the various attributes

needing

verification.

In addition, the inspector

noted that personnel

safety

was maintained during the evolution.

The procedure

required several

revisions during the process

but each time work was stopped until the

revisions were completed.

Conclusions

The inspector

concluded that although it required several

revisions

during its performance,

the procedure

was proper ly performed.

The

requi red Technical Specification

was satisfied.

E2

E2.1

'1

III. En ineerin

Engineering Support of Facilities and Equipment

En ineerin

Su

ort of Facilities and

E ui ment

37551

Inspection

Scope

The inspector

reviewed three separate

Engineering

issues that occurred

during the Unit 2 outage.

First. several

Hotor Operated

Valve (HOV)

torque switches

could not be properly set.

Second.

an In Service

Inspection (ISI) program inspection identified unacceptable

indications

in Safety Injection (SI) piping.

Third, Ultrasonic Testing

(UT) of Hain

Steam

(HS) piping indicated that the wall thickness of the pipe would

not be greater than the minimum wall thickness at the end of the next

cycle.

The inspector

reviewed the evaluations,

operability assessments,

and calculations.

Observations

and Findings

Dur'ing the Unit 2 outage,

the licensee identified that the torque

switches for the Pressure

Operated Relief Valve (PORV) block valves

and

the

HS Isolation Bypass

Valves were not functioning properly.

Condition

Reports were written on both problems.

Condition Report 97-1034

documented

the

PORY problem and

CR 97-1021

documented the

HS isolation

discrepancy.

The

PORV block valves are three inch gate valves with SB-00 actuators.

Electrical Haintenance

was unable to set torque switches

to meet the

Engineering specified torque values.

They were able to set the open

torque switch such that valve thrust at the torque switch trip was

greater than the minimum required valve thrust.

However. the corrected

maximum allowable total thrust and the corrected

maximum thrust at the

torque switch trip was exceeded

for the opening stroke.

Engineering determined that the

PORV block valves were acceptable for

use

as left.

The Engineering specified torque values

were too

conservative.

The inspector

reviewed the disposition

and determined

that the assumptions

and calculations

were appropriate.

The

HS bypass

valves are three inch globe valves with SB-00 actuators.

The

1B valve did not produce sufficient thrust to open the valve under

the design basis pressure differential.'Replacing the valve yoke did

not improve the valve's performance.

The lA valve worked properly until

heated,

at which point, the unit also could not produce sufficient

thrust.

The Engineering evaluation for the

HS bypass

valves did not

accept the valves

as left.

These valves are required to shut

on a

containment isolation signal.

However, the licensee

could not show that

these

valves could perform their function under all circumstances.

The

valves were deenergized

shut before restarting the unit pending further

disposition.

'2

Routine ISI of the 2Al SI Tank piping detected the presence of surface

discontinuities in the austenitic stainless

steel

pipe.

The flaw size

was in excess of that allowed in the class

2, six inch, schedule

160

piping.

American Society of Mechanical

Engineers

Boiler and Pressure

Vessel

Code

(ASHE) Section

XI required that unacceptable

flaws be

removed

or reduced to an acceptable

size.

The flaws. were chased

through the final area resulting in a wall thickness

reduction of 0.2

inches.

Engineering determined that the depth,

wandering,

and branching

of the flaw were indicative of Chloride Stress

Corrosion Cracking.

No

internal pipe degradation

was noted.

ASME Section XI,

IWC 2430 also required

an increased

scope of the

inspection to include an additional

number of components within the same

examination category,

approximately equal to the number of components

examined initially.

The licensee

examined four more areas

and

determined that three of the areas

were acceptable.

The fourth area

was

ground out and blended

as allowed by Section XI.

The inspector verified

that the dispositions

agreed with the

ASME code.

The corrective actions

were appropriate,

and the documentation

was adequate.

On May 5, routine

UT of the

HS piping revealed that an area

near the

2D

Moisture Separator

Reheater

(MSR) had

a wall thickness

below the

screening

thickness for that grade pipe.

The pipe supplied main steam

flow to the

HSR reheater

bundle.

This non-safety related

system pipe

was standard wall constructed of American Society for Testing

and

Materials

(ASTH) A106 GR

B material.

The wall thinning was general

in

nature,

indicating flow accelerated

corrosion.

Engineering

performed

a minimum required wall thickness calculation for

the pipe per

ASHE Boiler and Pressure

Vessel

Code Case

N-480.

The

calculation indicated that the actual piping thickness

was greater than

the minimum requi red then,

but would be less than minimum before the

next outage.

The inspector verified that the Code case

was properly

used

and implemented,

and determined that the conclusion

was sound.

Engineering

performed

a localized wall reduction calculation to further

refine the immediacy of the replacement of the piping.

They determined

that,

for the small area in question, waiting until the next outage to

replace the section of piping was acceptable.

The inspector

reviewed

the calculations

and assumptions

and concluded that they were in

accordance

with the applicable

ASME code.

PNAI 97-05-160

was generated

to track replacement of the pipe during the next short notice outage of

sufficient. duration -and conditions.-

c.

Conclusions

The inspector

reviewed several

specific cases of Engineering's

evaluations of physical plant problems during the outage.

In all cases,

the reviews were well prepared.

The staff adhered to all applicable

codes,

and the decision processes

were well documented.

E2.2

" 23

En ineer in

Su

ort of Crosb

Relief Valve Re lacement

37551

Inspection

Scope

In August 1995,

Crosby Valve and

Gage

Company informed the licensee that

they had identified blowdown concerns

on twenty-three. relief valves sold

to St. Lucie.

Crosby stated that these

valves

had either variations in

blowdown setpoints

and/or the setpoints

were not confirmed

by

operational testing.

The licensee initiated

a St. Lucie Action Report.

STAR 1-951024

on August 31,

1995 to evaluate the issue.

Of the twenty-

three valves identified, the licensee

determined that ten were currently

installed in Unit 1 and none were installed in Unit 2.

Recently.

a

Condition Report

was issued

(CR 97-0514)

asser ting that one of these

valves should

have been replaced last Unit 1 outage,

but was not.

The

inspector.reyi.ewed,,the

facts behind the original

STAR and examined the

adequacy of Engineering's

management

of the issue.

Observations

and Findings

The final disposition of the

STAR was completed

on October 6,

1995.

It

individually evaluated

and accepted for use the ten installed valves.

The assessment

concluded that the relief valves would function as

designed

and tested with the cur rent blowdown values.

Safe

oper ation of

the plant during all operating conditions would not be affected,

and

variations

and lack of blowdown data were not considered

a substantial

safety hazard.

The STAR also

recommended that the valves should be

replaced at the ear liest opportunity once replacements

were available.

The STAR was assigned to Planning to replace

and/or retest these valves.

In March 1996, the

STAR process

was replaced

by the Condition Report

process.

The STAR was administratively closed

on March 30,

1996 and

PMAI PM96-03-733 was issued with Engineering

as the responsible

organization.

No action had been taken by Planning

due to outage

preparations

and limited resources.

Engineering did not immediately

pursue the

PMAI due to lack of time before the outage"(less

than one

month), other priorities related to the outage.

lack of certified

replacement

valves,

and lack of funding.

After the last Unit 1 outage,

Engineering coordinated with Juno

Beach

and 'Planning to respond to the PMAI.

Ten work requests

were initiated

to replace the installed Unit 1 valves.

Additionally. the licensee

addressed

the use of Crosby spares

programmatically

'by issuing Procedure

GMP-14; -"Inspection.and

Maintenance-of .Crosby Relief-Val-ves."

- This

procedure

ensured that actual

blowdown tests satisfy the design

requirements of the system.

This way,

.a non-qualified Crosby valve

could not be installed in either unit.

Since last August, the 'licensee

has

been actively working on replacing

'he

valves.

The licensee

has budgeted

funds for offsite blowdown

testing.

Installation of the qualified valves

has

been scheduled

for

the. upcoming Unit 1 fall outage.

Conclusions

'4

E2.3

The licensee

has taken appropriate

actions to determine the significance

and effect of the non-qualified Crosby valves

on the plants.

Furthermore,

the licensee's

decision to retest the affected valves

and

to replace

any as required is reasonable.

However, the licensee

exhibited poor project prioritization as evidenced

by the eight months

that the

STAR resided with Planning without any action taken to closeout

the item.

Unit 2

DDPS Software Revision Error

92903

Inspection

Scope

The inspector

reviewed documents

associated

with erroneous

computer data

which affected the reactor calorimetric calculations.

These

documents

included

CR 97-1185.

several

WOs,

and

PC/M 96147.

In addition, the

inspector attended

the

FRG meeting which discussed

the event

and actions

taken to resolve the condition.

Observations

and Findings

During the Unit 2 refueling outage,

both feedwater

flow venturis were

removed.

cleaned,

and recalibrated.

The recalibration resulted in the

need to change the span of the flow transmitters

from 0-800 inches water

to 0-900 inches water.

This, in turn, resulted in a revision to the

span of each feedwater flow input to the Digital Data Processing

System

(DDPS) flow calculation.

The

DDPS software was modified in accordance

with PC/M 96147

and

WO 970115831A.

During the startup following the refueling outage,

the licensee

performed

manual calorimetrics at various

power levels to ensure that

,they compared favorably with the

DDPS,

as part of the post modification

testing of'he

DDPS.

This verification and validation

(V8V) was being

performed

as part of the corrective action from an event

on Unit 1 in

which the

DDPS was discovered to contain erroneous

data

and resulted in

incorrect power indication.

This requirement

was tracked by Plant

Managers Action Item (PMAI) 97-03-055 with a requi red completion of

"prior to Unit 2 startup."

On May 26, the manual calorimetric indicated

a reactor

power level of

50.6 percent while the

DDPS indicated 47.7 percent.

The reactor

engineer

recalibrated the

RPS instrumentation to the higher,

more

conservative,

value.. At 80 percent

power, another

manual calorimetric

was performed which indicated

5 percent

higher

than the

DDPS.

The licensee's

investigation revealed that the discrepancy

was the

result of an incorrect instrument

span

from the feedwater flow

instrumentation

which input to the, calorimetric performed by the

DDPS.

Although the licensee

had modified the span of the feedwater flow

inputs. they had failed to identify that the feedwater flow averaging

circuit also required

a revision based

on the new span.

This resulted

'5

in the calculation performed by this circuit to be based

on

a span of

800 inches of water vs 900 which resulted in the observed error.

Once

identified, the licensee

changed the span in the feedwater flow

averaging circuit within DDPS in accordance

with WO 9701271901,

and

reperformed the manual calorimetric'with satisfactory results.

The inspector discussed

with the licensee

why the corrective actions

taken in response to the Unit 1

DDPS event,

discussed

in paragraph

E8.2

of this report

and in LER 50-335/97-002,

did not prevent this event from

occurring.

The licensee stated that the feedwater

flow averaging

ci rcuit is actually computer

code that can only be changed

by a

modification to the source

code.

It was not'

constant that could be

changed

due to,plant conditions.

The licensee stated that. while all

other constants

loaded into DDPS were verified to be correct, the code

was not.

Therefore, it was not considered to be included as part of the

corrective action for the Unit 1 events

The inspector

reviewed

PC/0 96147

and discussed

the methodology the

licensee

used in determining which DDPS components

needed modification.

The licensee stated that because

there

was

a recognized

lack of

expertise

on this system within FPL, vendor expertise

was solicited to

determine what

DDPS modifications were necessary

as

a result of the

feedwater flow transmitter

span change.

Neither the vendor

nor the

licensee identified that the feedwater

averaging circuit required

a span

change.

However, the licensee

had developed

a

VLV plan which would

encompass

the modifications being performed such that the system

as

a

whole would be tested prior to'being completely returned to service.

Although the averaging circuit was not identified during the design

and

implementation stage,

the licensee did identify the error during the

return to service test.

As part of the corrective action of this event, the licensee

reviewed

the

DDPS software to identify other incidents where similar problems

existed.

Two additional similar averaging circuits were identified. the

feedwater temperature

averaging circuit and the steam generator

A and

8

pressure

averaging circuit but were determined

not to contain errors.

In addition, the following is

a list,of corrective actions the licensee

is taking in response to this event.

PHAI

97-03-057

DUE DATE

Complete

~ DESCRIPTION

Develop operating procedures

for DDPS which

will identify all the points

and their

locations.

26

PMAI

97-03-279

97-03-61

97-03-273

97-03-274

97-03-278

97-03-055

97-03-056

97-03-059

.,97-03-060

97-03-058

97-03-275

97-03-276

DUE DATE

Complete

9/30/97

8/30/97

Complete

9/30/97

3/31/98

11/30/97

3/31/98

12/29/97

DESCRIPTION

Identify the responsibilities of the various

disciplines that are involved in work relating

to computer systems.

(AP 4000060,

Revision 3,

"Maintenance

Departmental

Control of Computer

Software,"

has

been issued but on hold pending

training.)

Perform point check

on all Unit 2 DDPS inputs.

(Unit 1 was

reviously checked.)

Revise

AP 4000060

and Nuclear Engineering

QI

3.7,

"Computer Software Control," to provide

ade uate

ost-maintenance

testing.

Revise existing

PCM process to include

ade uate

ost maintenance testing.

Create master

and backup copies of software

f'r the Unit 2 generator

temperature

monitoring computer,

M&TE calibration

computer,

and the radiation monitoring

corn uter.

Develop generic

V&V requirements to challenge

all critical attributes within both Unit 1 and

Unit 2

DDPS for all software changes.

Develop generic

V&V requirements to challenge

all critical attributes within both Unit 1 and

Unit 1

DDPS for all software changes.

Revise Unit 1

DDPS software to reflect the

correct calibration curve for the feedwater

tern erature

RTDs.

Revise Unit 1

DDPS software to reflect the

correct calibration curve for the Reactor-

Coolant

Pum

Watt Transducers.

Ensure configuration control for all

critical'nit

1 and Unit 2 DDPS constants

by entering

them into TEDB or ensuring they are documented

in a controlled

roc'edure.

Develop the baseline

V&V plan for the-battery

test data collection system.

METE calibration

system.

and Units

1 and

2 time response

RPS

systems.

Evaluate the need for a

V&V plan and develop

if required for Units

1 and 2 generator

temperature

monitoring system

and Units

1 and

2 se uence of events

recorders.

27

PMAI

DUE DATE

97-03-277

7/1/98

97-06-288

8/31/97

97-06-289

3/31/98

97-06-290

3/1/98

c.

Conclusions

DESCRIPTION

Evaluate the need for a

V8V plan and develop

if required for air condition unit maintenance

tracking system,

Units

1 and

2 DDPS,

and Units

1 and

2 turbine control systems.

Modify Units

1 and

2 DDPS

VBV test plans to

provide testing for each of the believable

value

rocessor

averaging/scaling

functions.

Evaluate the need for computer systems

software training and software

VSV training.

Ensure software control program improvements

implemented in response to PMAI 97-03-054

address

the lessons

learned

from this event

and from the Turkey Point eagle

21 software

V8V event.

E8

Although the original modification package failed to identify .all the

components

requiring revision, the post-modification

V8V adequately

encompassed

the system such that the error

was properly identified.

Miscellaneous

Engineering Issues

E8.1

Closed

URI 50-335/94-08-03

" ualit

Level of PORV and

SRV Dischar

e

Pi in "

92903

a.

Inspection

Scope

This item involved a concern regarding the licensee's clarification of

the safety classification of the pressurizer

PORV and safety relief

valves

(SRV) discharge piping.

The inspection effort focused

on the

licensee's

corrective actions to address this unresolved

item and the

review of other

r elated documentation.

b.

Observations

and Findings-

r

The inspector

reviewed the licensee's

actions for compl,iance with

applicable sections of the

UFSAR, TS,

and licensee

procedures.

The

inspector noted that the Unit 1 pressurizer

PORV and

SRV discharge

piping was designated

as quality group

D (non-safety related)

and non-

seismic by the licensee.

During the review of various design documents,

applicable

UFSAR sections,

and

FPL correspondence

to the

NRC, the

inspector

determined that, although the pressur.izer

PORV and

SRV

discharge piping was designated

as non-seismic,

the licensee

had

seismically analyzed the discharge piping and supports.

'The inspector

noted that analyses

performed

by the licensee

included the Unit 1

American National Standards

Institute (ANSI) 831. 1 Class

1 Stress

'8

. Analysis for the Pressurizer

Relief Valve Piping, Seismic Analysis

Performed

on Discharge Piping,

and the Seismic Anchor and Restraint

Movement Analysis.

Conclusions

The inspector

concluded

from review of the

UFSAR and applicable design

documents that the Unit 1 pressurizer

PORV and

SRV discharge piping was

designated

as quality group

D (non-safety related)

and non-seismic

by

the licensee.

The inspector further concluded that,

although the

pressurizer

PORV and

SRV discharge piping was designated

as non-seismic,

the licensee

had seismically analyzed the discharge piping and

associated

supports.

This URI,is closed.

EBS 2

Closed

URI 50-335/97-03-07

"Issues Relatin

to Exceedin

Unit 1

Licensed

Stead

State

Power Levels"

92903

This URI involved maintenance

and engineering

issues relating to Unit 1

exceeding the steady state licensed

power level of 100 percent

as

'eported

in IR 97-03.

Specifically, four issues

were identified and

included the following:

1.

Whether the licensee's

software

VSV processes

were adequate

and in

agreement with the licensee's

OA Plan.

2.

Whether the licensee's

OA Plan requi rements

were violated

regarding control of software

and manuals.

3.

Whether corrective actions to previous events

should have

prevented this event

and whether

data available to the licensee

should

have resulted in earlier detection of the condition.

4.

The extent to which licensed steady state

power limits for Unit 1

were exceeded

during the current Unit 1 fuel cycle.

With regard to items

1 and 2;

In June,

1994,

feedwater flow scaling

constants

were revised in accordance

with plant procedures

and were

subsequently

installed into the

DDPS.

However, the new constants

were

not added to the Master/Backup

copy of the software..

10 CFR 50 Appendix

B Criterion

V requi res, in part, that activities affecting quality shall

be prescribed

by documented instructions,

procedures,

or drawings of a

type appropriate to the circumstances

and shall

be accomplished

in

accordance

with these instructions,

procedures,

or drawings:

., Procedure

QI 2-PR/PSL-3,

Revision 0, "Control- of Computer Software,"

was

the'ocument

which implemented this requirement with respect to the control

of revisions to computer

software.

Step 5.5 of that procedure required that

a form similar to Appendix A

Form 2 of that procedure

be used to document revisions to software.

This form required information such

as the impact the change would have

on the plant, the documentation that needed revision, the installation

instructions,

contingency instructions,

a validation test plan

29

independent verifications,

and implementation sign-offs.

In addition,

step 5. 10.2 stated,

in part, that "computer software access

shall

be

controlled in order to ensure that only approved versions [of software]

are in use.

and modifications are authorized with written approval."

Step 5. 10.5 stated that

"measures

shall

be taken to 'ensure

superseded

or

invalid computer software is not available for use."

.

Contrary to the above,

these

steps

were not followed to control

and

document the revision to':the

FW flow constants

in the

DDPS.

As

a

result. the master/backup

copy of the software

was not revised which

ultimately resulted in the wrong revision being reinstalled

and used in

the

DDPS.

The licensee identified this problem while performing repai rs

on

a feedwater

flow transmitter

and corrected it the next day.

The inspector

found that this was not a violation that could reasonably

have been prevented

by the licensee's

corrective action for a previous

violation that occurred within the past two years.

Actions were taken

within ten minutes to alleviate the concern raised

by the problem and it

was corrected

by modification within twenty hours of discovery.

Further, it was not apparent that the failure to use the appropriate

procedure to document

and control the software revision was willful.

Therefore, this licensee identified and corrected violation is being

treated

as

a Non-Cited Violation, consistent with Section VII.B.1 of the

NRC Enforcement Policy.

This issue wi 11

be treated

as non-cited

violation NCV 50-335/97-05-04,

"Failure to Use the Proper Procedure to

Document

and Control

DDPS Software Revisions."

The licensee's

investigation concluded with the same root cause

which was documented in

LER 50-335/97-002.

With respect to item 3, the inspector

reviewed

LER 50-335/86-005-00,

which related to a failure to proper ly reinitialize the Unit 2 DDPS

computer such that old incore detector sensitivities

were loaded (these

sensitivity values are periodically updated

by DDPS to account for

burnup of the rhodium detectors

which comprise the incore strings).

While the subject

LER did relate to the control of software,

the issue

did not relate di'rectly to the current issue in a way. that would

constitute

a prior opportunity to identify the current issue.

With respect to the fourth item, the inspector

reviewed the licensee's

root. cause evaluation for the subject event to verify the maximum power.

level reached

during the event.

The licensee initially estimated

l3DPS

calorimetric power to be indicating approximately

.63 percent. lower than

actual

power.

This estimate

was based

on the, mathematical

results of

comparing the as-found feedwater flow scaling constant to the correct

value for the constant.

In the course of the root- cause investigation,

the licensee identified two additional, conservative.. errors involving

instrument calibration which offset the initial estimate of maximum

power error.

The first error involved the selection of calibration curves for

temperature

RTDs.

The

RTDs sensing

temperature

were

comprised of two manufacturer

types;

Rosemount

and

WEED.

The l,icensee

J

30

found that the temperature

sensing circuits employing Rosemount

RTDs

were calibrated using the generic

WEED RTD curves

used for the

WEED

RTOs.

The net effect was that the Rosemount

RTOs were reporting

temperature

approximately 1.5 degrees

too low.

When incorporated into

the calorimetric calculation, this tended to overestimate

power by

approximately

. 14 percent.

While the effect on the calorimetric

calculation

was conservative,

the inspector

found. through interviews

with personnel,

that this effect was fortuitous.

The licensee

had

issued

a

PHAI to address:this

issue (to correct the curve), but the

inspector

found that the licensee

had taken

no action to determine

how

the erroneous calibration curve had been applied.

The inspector

considered this

a weakness

in the licensee's

root cause effort.

The second error involved the scaling of RCP watt transducers.

The

transducers

were designed to provide

a milliampere

(mA) output

proportional to power input by the pumps.

The error resulted in a

1

mA

output equating to 8600

kW, versus

9600

kW, as designed.

When these

errors were factored into the calorimetric calculation,

the error tended

to overestimate

reactor

power by approximately

.06 percent.

As in the

case of the feedwater

RTOs, the inspector

found that, while the licensee

intended to correct the settings

associated

with this discrepancy,

the

licensee

had initiated no efforts to determine

how the error came to be

in the first place or to ensure that the proper level of controls

existed for this setpoint.

Upon discussing the issue with the licensee,

a

CR was generated to determine the cause for the transducer

setting

inaccuracy.

When the two errors described

above were factored in against the

estimated

.63 percent

nonconservative

error already identified, the

effect was to offset that. error.

The net result was

a .43 percent

nonconservative

power error in the

DDPS calorimetric calculation.

Consequently.

Unit

1 operated at approximately 100.43 percent of rated

thermal

power for those periods during the current fuel cycle when

indicated reactor

power was

100 percent.

Regarding safety significance,

the inspector noted that the safety

analysis for Unit 1 assumed initial power conditions of 102 percent for

.all pressure

The inspector discussed

the degree of known uncertainty in power measurement

with the licensee.

The maximum uncertainty

was determined to 1. 16 percent.

When the known

calorimetric error

was added to the known uncertainty figure, the. worst

case

power error total

was 1.59 percent,

which was within the 2 per cent

nonconservative

error assumption

made in the accident analysis.

The

inspector

concluded that the unit was not outside of'ts accident

analysis

as

a result of the "subject condition.

'.

Conclusions

The inspectors

concluded that the

DDPS inaccuracies

leading to steady

state

power levels in excess of licensed limits were the result of a

failure on the part of the licensee to properly employ software controls

in 1994.

The inspectors

found that the licensee's

root cause effort

i'-"4

E8.3

E8.4

S8

S8.1

'1

was, in general,

comprehensive

and that the licensee

had properly

assessed

the safety significance of the event;

however,

two weaknesses

involving failures to establish

root causes

were identified.

Closed

URI 50-335/97-03-05

"Failure to Obtain

FRG Review for Interim

CR Dis osition"

92903

The inspector

discussed this issue with the licensee,

who stated that

the "disposition" referenced

in this

URI was,

instead,

an "operability

determination,"

covered

by

a different portion of procedure

AP-0006130,

Revision 7, "Condition Reports,"

from that requi ring

a

FRG review.

The

inspector

reviewed the subject

CR, the licensee's

TQAR, and

NRC Generic Letter 91-18 (which discusses,

through attachments,

degraded

and

nonconforming conditions) in this light and found the licensee's

position acceptable.

The subject determination

was not

a disposition of

the condition at the time it was prepared,

a disposition

was being

prepared at the time in an expedited

fa'shion,

and corrective actions

were implemented promptly.

As the subject determination

was not

a

disposition to the condition, it did not require

a

FRG review.

This

item is closed.

Closed

URI 50-335/97-03-06

"Post Maintenance Testin

Issues

Associated with DDPS Constant

Chan es"

92903

This issue

r elated to a fai lure on the part of the licensee to perform

a

nuclear

and delta-T calibration of the NI system

as post-maintenance

testing following the installation of correct

flow spans into

DDPS.

The licensee stated that the purpose of post-maintenance

testing

was to ensure that the component

which had received maintenance

was in

proper working order following the maintenance.

The licensee

contended

that the appropriate

post-maintenance

test for DDPS feedwater flow span

changes

was

a manual calorimetric (which was, in fact, performed) which

would compare

DDPS on-line calorimetric output to the manual result.

The inspector

agreed that the manual calorimetric was the appropriate

post-maintenance

test for the subject work and that no violation

existed.

This item is closed..

IV. Plant

Su

ort

Hiscellaneous

Security and Safeguards

Issues

Closed

IFI 50-335 389/96-16-03

"Im lementation of Interim Plant

Actions to Detect

New Tam erin

"

92904

This item was identified to follow licensee's

interim actions to detect

new tampering following an event involving suspected

tampering of plant

equipment.

These interim actions

included daily plant inspections

by

system engineers,

managers,

and personnel

responsible for housekeeping

in certain locations, of specific areas

looking for evidence of

tampering.

In addition, Condition Reports

and Work Orders were reviewed

dai3y f'r conditions which could have resulted

from tampering.

Finally,

operational

checks of specific equipment

were performed to assure

proper

F5

F5.1

b.

'2

operation.

The inspectors

witnessed

many of these activities.

After a

discussion with NRC Regional

management,

the licensee discontinued

these

interim actions.

This IFI is closed.

Fire Protection Staff Training and Qualification

Fire Bri ade Leader

Chan

es

64704

Inspection

Scope

Due to the lack of licensed

board operators.

the licensee

decided to

down relieve the Nuclear Watch Engineers

(NWEs) to RCOs temporarily.

Before this action, the

NWEs were the fire brigade leaders.

The

licensee

determined that the Senior

Nuclear Plant Operators

(SNPOs),

whowere non-licensed

operators,

would perform the function of the Fire

Brigade Leader.

The inspector

reviewed the qualifications of the

SNPOs

and reviewed the additional training required to meet all requi rements.

Observations

and Findings

Both units'ire Protection

Plans

meet the requirements of 10 CFR 50

Appendix

R with allowed exemptions.

Appendix R,Section III.H requires.

in part

...

The brigade leader

shall

be competent to assess

the potential

safety consequences

of .a fire and advise control

room personnel.

Such competence

by the fire brigade leader

may be evidenced

by

possession

of an operator's

license or equivalent

knowledge of

plant safety related

systems.

Section III.I(8) requires that fire brigade leaders

also receive

training on direction and coordination of fire fighting activities.

Both units'FSARs describe the fire fighting program as meeting these

portions of Appendix R.

Turkey Point has

used senior non-licensed

operators

as the fire brigade

leader for some time:

The training programs at St. Lucie and at Turkey

Point were designed to take

a person with little nuclear

power

background,

and, through time, increase their knowledge

and skills to a

point that they would be able to apply for a license.

The

SNPO position

was designated

for the most senior

and knowledgeable

non-licensed

operators.

Administrative Procedure,

AP 0005740,

"Non-Licensed Operator

Initial Training and Qualification," specifically states

the subject

matter that the non-licensed

operators

are required to know.

Besides

systems

knowledge

and practical operations training. the

SNPOs are

required to exhibit knowledge of integrated plant operations.

During the weeks of Hay 26 and June 2, the licensee

conducted fire

brigade leader training for the SNPOs.

This was the same type of

training that the

NWEs routinely receive.

The inspector attended

portions of the training.

Class sizes

were small, generally five to

eight members.

The instructor s presented

the lesson

plans well,.

The

P

'3

inspector noted that many good questions

were asked

by the

SNPOs

and

that the participation levels were high.

The subject matter covered

was

appropriate.

The first topic covered

was

on procedures

and procedural

requirements.

All applicable procedures

were discussed,

particularly

the Emergency

Plan implementation.

The instructors

discussed

the

classification of fire related events,

and what type of help was to be

expected

from outside sources.

Next, the group discussed

leadership qualities

and

how to be

a leader.

It was evident to the inspector that there were

some

SNPOs

who held

reservations

about being the fire brigade leader,

but private

discussions

with the operators

at later times indicated that very few

doubted that they would be able to perform the function if necessary.

After this, the discussions

turned to the duties of the fire brigade

leader.

Again, the inspector

noted .that good conversations

were held.

Finally, the

SNPOs role played

some fire scenarios.

As the instructor

facilitated the discussions,

the team members

discussed

the best places

to set

up command posts,

how to distribute personnel.

hazardous

material

issues,

and other topics.

Overall the quality of training was judged to

be good.

The licensee

had plans to run drills with the

SNPOs acting

as

fire brigade leaders

when possible.

c.

Conclusions

The training to allow the

SNPOs to up relieve as fire brigade team

leader

was adequate to meet all. regulatory requirements.

The brigade

leader training was comparable to that which the

NWEs receive.

V. Hang ement Heetin

s and Other

Areas

Xl

Exit Meeting Summary

The inspectors

presented

the inspection results to members of licensee

management

at the conclusion of the inspection

on June 20,

1997.

An interim

exit meeting

was held on May 23.

1997, to discuss

the findings of Region based

inspection.

The licensee

acknowledged

the findings presented.

The inspectors

asked the licensee

whether

any materials

examined during the

inspection should

be considered proprietary.

No proprietary information was

identified.

-.

Licensee

'4

PARTIAL LIST OF

PERSONS

CONTACTED

M. Allen. Training Manager

C. Bible, Site Engineering

Manager

.

W. Bladow, Site Quality Manager

G. Boissy, Materials Manager

H. Buchanan,

Health Physics Supervisor

D. Fadden,

Services

Manager

R. Heroux.

Business

Manager

H. Johnson.

Operations

Manager

J.

Marchese,

Maintenance

Manager

C. Marple. Operations

Supervisor

J. Scarola,

St. Lucie Plant General

Manager

A. Stall, St. Lucie Plant Vice President

E. Weinkam, Licensing Manager

W. White, Security Supervisor

Other licensee

employees

contacted

included office, operations,

engineering,

maintenance,

chemistry/radiation,

and corporate personnel.

INSPECTION

PROCEDURES

USED

IP 37551:

IP 61726:

IP 62703:

IP 62707:

IP 64704:

IP 71707:

IP 92901:

IP 92902:

IP 92903:

IP 92904:

~0ened

Onsite Engineering

Surveillance

Observations

Maintenance

Observations

,

Maintenance

Observations

Fire Protection

Program

Plant Operations

Followup - Plant Operations

Followup - Maintenance

Followup - Engineering

Followup - Plant Support

ITEMS OPENED,

CLOSED,

AND DISCUSSED

50-389/97-05-01

"Failure to Control Foreign Material Entering

and Exiting the Unit 2 Containment."

(paragraph

3.1)

50-335,389/97-05-02

IFI

"Licensee

Review and Clarification of Procedure

(ADM-11.03) for Performing Temporary Changes to

Procedures."

(paragraph

08. 1)

50-335/97-05-03

"Failure to Provide Adequate

Work Instructions

For

a Work Order." (paragraph

M1.3)

50-335/97-05-04

Closed

50-335/94-08-03

r

50-335,389/96-01-01

50-335,389/96-16-03

50-335/97-03-07

50-335/97-03-05

50-335/97-03-06

Discussed

50-389/97-03-04

'5

NCV

"Failure to Use the Proper Procedure to Document

and Control

DDPS Software Revisions."

(paragraph

E8.2)

"Quality Level of PORV and

SRV Discharge

Piping." (paragraph

E8.1)

"Temporary Changes to Procedures

Improperly

Changed Intent of Procedures."

(paragraph

08. 1)

IFI

"Implementation of Interim Plant Actions to

Detect

New Tampering."

(paragraph

S8. 1)

"Issues Relating to Exceeding Unit 1 Licensed

Steady State

Power Levels." (paragraph

E8.2)

"Failure to Obtain

FRG Review for Interim CR

Disposition" (paragraph

E8.3)

Emergency Diesel Generator

"Post Maintenance Testing Issues

Associated with

DDPS Constant

Changes"

(paragraph

E8.4)

NCV

"Nonconforming Reactor

Coolant

Pump Penetration

Fault Protection"

(cover letter)

ADM

ANSI

ASME Code

ATTN

CFR

CIAS

CNRB

CR

DDPS

LIST OF ACRONYMS USED

Administrative Procedure

Auxiliary Feedwater

(system)

American National Standards

Institute

Administrative Procedure

American Society of Mechanical

Engineers Boiler and Pressure

Vessel

Code'merican Society for Testing

and Materials

Attention

Control Element Assembly

Code 'of Federal

Regulations

Containment Isolation Actuation Signal

Company Nuclear

Review Board

Condition Report

Containment

Spray Actuation System

Digital Data Processing

System

Departure

From Nucleate, Boiling Ratio

Demonstration

Power

Reactor

(A type of operating license)

Enforcement Action

Emergency

Core Cooling System

ESF

FHE

FPL

FR

FRG

FSAR

FW

GMP

gpm

HCV

HPSI

I8C

ICW

IFI

ISI

kW

LER

LOOP

LPSI

LR

mA

M8TE

HOV

MS

MSIV

MSR

NCV

NI

No.

NOP

NOV

NPF

NPS

NPWO

NRC

NWE

OP

OPC

PC/M

PDR

PGM

PMAI

PORV

PSL

.

QA