ML20129A214

Insp Repts 50-327/96-09 & 50-328/96-09 on 960728-0914. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20129A214
Person / Time
Site:	Sequoyah
Issue date:	10/10/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20129A195	List: ML20129A194 ML20129A210 ML20129A214
References
50-327-96-09, 50-327-96-9, 50-328-96-09, 50-328-96-9, NUDOCS 9610220067
Download: ML20129A214 (31)

See also: IR 05000327/1996009

Text

- _-

. .

'

.

U.S. NUCLEAR REGULATORY C0l#11SSION

REGION II

Docket Nos: 50 327, 50 328

License Nos: DPR 77, DPR 79

Report Nos: 50 327/96 09, 50 328/96 09

Licensee: Tennessee Valley Authority (TVA)

.

Facility: Sequoyah Nuclear Plant, Units 1 & 2

i

Location: Sequoyah Access Road

Hamilton County, TN 37379

Dates: July 28 through September 14, 1996

Inspectors: M. Shannon, Senior Resident Inspector

W. Holland, Senior Resident Inspector

R. Starkey, Resident Inspector

J. Blake, Reactor Inspector, (Sections H3.1, M6.1,

M8.1, E2.1)

G. MacDonald, Reactor Inspector,(Sections M1.2,M1.3,

& H2.4)

K. VanDoorn, Senior Resident Inspector Watts Bar,

(Section 03.1)

Approved by: M. Lesser, Chief

Reactor Projects Branch 6

Division of Reactor Projects

.

Enclosure 2

eA 88e?oes8s827

G PDR ,

_ .. _._ __ _ _ ___ - ._ _ _ . _ . . _.. _ .. _ _ .._ _ . . . _

, o

>

. .

.

'

l

i

, 2

i

.

.

EXEClTlIVE SUMMARY

i

j Sequoyah Nuclear Plant, Units 1 & 2

NRC Inspection Report 50 327/96 09, 50 328/96 09

-

This integrated inspection included aspects of licensee operations,

maintenance, engineering, riant support, and effectiveness of licensee

1 controls in identifying, resolving, and preventing problems. In addition, itL

! includes the results of announced inspections by engineering and maintenance

j inspectors.

Ooerations

! e' Negative observations were noted in the areas of operation's log keeping

detail, emergency diesel generator starting air system operation,

4

operation's log keeping status control, and guidance in operator rounds

j (Sectioas 01.2 and M1.1).

!

i e Back filling of pressurizer level transmitters presented a potential

safety hazard to personnel and could result in a breach of the reactor

coolant system (RCS) (Section 02.2).

4

i e A weakness was identified in the control of certain engineering

documents provided to control room operators (Section 03.1).

e A non cited violation (NCV) was identified for the placing of an

i Emergency Gas Treatment System (EGTS) dam mr control switch in the wrong

i position which rendered the "A" train of iGTS inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and

,

43 minutes (Section 03.2).

1

e Technical Specification (TS) wording does not accurately reflect the

, current shift hours worked by operations personnel. However, the

i licensee has been in compliance with the TS guidelines regarding use of

j

'

overtime and has initiated a proposed ct,ange to TS to clarify normal

shift hours (Section 08.1).

!

l Maintenance

J

'

e Maintenance and surveillance activities observed were satisfactorily

wrformed in accordance with licensee procedures. A weakness in

4

Emergency Diesel Generator (EDG) maintenance trending was noted

regarding not performing any compensatory measures for failed EDG

j cylinder exhaust gas temperature parameters (Section M1.2).

i e Several completed work orders were reviewed and the level of detail of

work documentation was adequate but not thorough. A minor documentation

4

weakness was noted in a mechanical maintenance work order which was

corrected by the licensee (Section M1.3).

I,

i

i

_ _ _ _ _ _J

. _

'. .

'

.

3

e An ERCW pump discharge check valve stuck open due to wear and resulted

in a system backflow of approximately 3000 gallons per minute.

Subsequently, engineering determined that the stuck open ERCW pump

discharge check valve had been installed incorrectly (Section M1.4).

e Repetitive equipment problems caused added operator burden and impacted

maintenance resources, operation's switching and tagging resources, and

day to day operations (Section M2.3).

e Corrective action for the Emergency Diesel Generator (EDG) Governor

Booster Servomotor was satisfactory (Section M2.4).

e Steam Generator records indicated that the licensee has implemented a

comprehensive program to minimize stress related degradation of Steam

Generator tubes (Section M3.1).

e The licensee *s Steam Generator organization has done a very good job of

reviewing their inspection and repair options, and then soliciting plant

and corporate management support for the options selected (Section

M6.1).

Enaineerina

e After identification of initial concerns based on the engineering

evaluation for a Part 21 potential problem associated with material, the

licensee took appropriate positive actions to determine the issue did

not affect Sequoyah (Section E2.1).

i

e A weakness in the licensee *s process for design control of system

operational status wa: identified. Sample valves located in the Unit i

hot sample room for the Safety Injection system were in poor material '

condition and presented potential housekeeping problems. In addition,

this portion of the sample system was not formally dispositioned as to

its operational status in the plant (Section E2.2).

e The practice of venting the residual heat removal (RHR) system prinr to

calculating the volume of gas in the system did not provide an accurate

representation of the total amount of gas in the RHR system (Section

E2.3). -

e A violation was identified for untimely and inadequate corrective

actions associated with the failures of the EDG starting air compressor

control switches (Section E4.1).

i

e A weakness was identified for the inadequate root cause evaluations

associated with the initial EDG starting air compressor control switch

failures (Section E4.1). '

o Weak engineering sup mrt and maintenance was indicated by repetetive

equipment problems w1ich added operator burden and impacted maintenance

resources (Section M2.3).

. . .. . _ . . _ _ _ . _ _ _ . _ . _ . _ _ -_ . ._, ___ _ ._ _

. o

.

.

!

i 1

'

4

Plant Supoort

e The licensee did not take adequate immediate corrective actions for a  !

i transient fire load issue identified during the week of July 8 - 12, i

1996. Appropriate corrective action was only taken after the Nuclear  !

,

Regulatory Comission (NRC) comenced additional review of the issue on

j July 30,1996 (Section F1.1).

!

!

t

i

i

i

i l

r  :

• l

1

!

1

i

j

,I

I

t

I

d

1

!

!

$

!

i

i

i

I

a

9

i

!

.

1

,

._.

--- -

= . - .- . . .

4

, .

. .

.

'

Report Details ,

'

.

Summary of Plant Status

Unit 1 began the inspection period in power operation. The unit operated at

power for the duration of the inspection period.

Unit 2 began the inspection period in power operation. The unit operated at

power for the duration of the inspection period.

I. Operations l

l

01 Conduct of Operations

l

'

01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent

i reviews of ongoing plant o In general, the conduct of

operations was acceptable.perations.Smcific events and notesorthy observatio'

are detailed in the sections slow.

01.2 Emeraency Diesel Generator Startina ,^1r System Ooeration

,

a. Insoection Scope (71707)

The control room logs were reviewed in order to determine the frequency

at which the EDG starting air system relief valves were lifting and to

'

determine what operational problems were being experienced as a result

of the various starting air compressor malfunctions. The supporting

documentation for the EDG starting air compressor control switch

problems is detailed in Section E4.1.

b. Observations and Findinas

While reviewing documentation and actions associated with the EDG

starting air compressor control switch failures, various observations

related to the conduct of operations were made. The following items

were identified during the review:

e The control room logs and the associated PERs did not always

identify which relief valve was lifting or identify the affected

compressor unit. The lack of engineering's and management's

knowledge that the receiver tank / system reliefs were lifting

appeared to contribute to the licensee's slow implementation of

corrective actions,

e Operation's actions, in responding to deficient conditions, were

considered to be weak in that on August 23 the 2A2 EDG starting

air system was found relieving and the compressor control was not

. -- - - - -

, *

. .

. ,

1

2 l

placed in "off" and approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> later the relief valve i

was found relieving again. In addition, on August 4 and again on j

September 10, after the 2A2 EDG stating air compressor was placed

in "off", the startia air system alarmed on low pressure.

e The September 8, control room logs documented that at 03:07 p.m.,

" fire operations" reported that the 1A A EDG air relief valve was

actuated. The logs for 03:34 p.m., documented that the

compressors were found in "off" and the relief valves were seated.

The logs did not document control room directions to alace the ,

compiessors in "off", did not document that the switcles had been I

placed in "off" following the 03:07 p.m., entry, and did not

document who placed the switches in "off".

e The logs noted that the operator increased receiver tank pressure

to 305 psig on two occasions. The normal operating band for

receiver pressure control was 250 300 psig and the low pressure i

alarm actuates at approximately 250 psig. The logs only consider '

an abnormal condition when pressure drops to less than 240 psig

and does not give the operator a limit for a high pressure

abnormal condition. Routinely, log reading limits are based on

the automatic operational setpoints for a system to ensure

abnormal operation is identified prior to the development of more i

serious deficiencies. j

a

c. Conclusions

The failure to identify the specific relief valves that were lifting in

the control room logs was considered to be' a negative observation.

The failure to maintain the starting air system within the normal

operational band when operational problems are known was considered to I

be poor implementation of compensatory measures.

The lack of status control in the control room logs was considered to be

a negative observation. .

!

The lack of clear guidance in operator rounds was considered to be a  !

negative observation. j

i

02 Operational Status of Facilities and Equipment  !

!

02.1 Main Control Room Alarms. Indications. and Control Deficiencies l

l

a. Insoection Scope (71707)

During the period of August 23 28, 1996, the inspectors walked down the l

main control room boards and the common boards of each unit. This l

walkdown, cccomplished over several days, had as its purpose to identify t

all the deficiencies, (Work Requests (WR), disabled annunciators,  !

l

- -- -. . - . - . - - - - - . ~ - - . . -- - _. - .- ~ .-

. .

,

c . .

'

.

i caution orders), on each unit and to determine Operator's awareness of

the deficiencies,

b. Observations and Findinas

'The inspectors noted 54 WR stickers in the Unit I horseshoe area, four

,

WRs on the nuclear instrumentation back panel and 39 WRs on the common

i control board (panels 1 M 15 through 0 M 15). These panels contained a

j

'

total.of 12 disabled or partially disabled annunciators and 12 posted

caution orders. When questioned about specific deficiencies, operators

did not always have a ready explanation for the deficiency, but

generally knew where to look to find the requested information.

4

.

c. Conclusions

1

The ins)ectors concluded that the number of deficiencies, as noted by

the num)er of WRs, disabled annunciators, and caution orders, made it

difficult for an operator to be cognizant of the nature of each

deficiency, thus placing an unnecessary work load on licensed operators.

,

02.2 Backfill of Pressurizer Level Transmitter

i a. Inspection Scope (71707)

4

'

,

The inspectors reviewed a recent Unit 1 evolution involving the

backfilling of a pressurizer (PZR) level transmitter reference leg and

the licensee's practice of bypassing and tripping related

instrumentation to accomplish the evolution.

b. Observations and Findinos

On August 28, 1996, the licensee documented in Problem Evaluation Report

4

(PER) No. SQ962300PER a level deviation between the three Unit 1 Main

Control Room (MCR) PZR level instruments (1 LI 68 320, 335, and 339).

The maximum observed level deviation between the instruments was 4%

,

while the maximum allowed deviation was St. On August 29, the licensee

initiated action to backfill the reference leg of 1-LT 68 320 to correct

l the problem.

The design of the PZR level / pressure instrumentation is such that 1 LT-

68 320 shares a common reference leg with two PZR pressure transmitters,

'

1 PT 68 322 and 1-PT 68 323. In order to fill the reference leg of 1-

LT 68 320, the two pressure transmitters had to be bypassed / tripped. TS 3.3.1, Reactor Tri) System Instrumentation, Table 3.31, requires that

three out of four )ZR pressure channels be operable in Modes 1 & 2, with

<

two channels required to initiate a unit trip. The licensee determined

that a recent change to the TS Bases allows one channel to be bypassed,

1 which would make that channel inoperable, and allows the second channel

! to be tripped. The TS Bases states that the placing of a channel in the

i tripped condition provides the safety function of the channel and if the

'

channel is tripped for testing and no other condition would have

indicated inoperability, the channel should not be declared inoperable.

.

!

.. .- - . - - .-- - -

, .

. .

.

.

~

4

Based upon the licensee's TS interpretation, operators bypassed 1 PT 68-

322 and tripped 1 PT 68 323 for the backfilling evolution. The licensee

successfully completed the backfillirg in less than two hours and

returned the protection system to a normal alignment.

The inspectors questioned the licensee on the necessity of backfilling

the level transmitter since the reference leg is designed with a

condensing pot would should ensure that the reference leg remains

filled. The licensee is evaluating the root cause as to why the

reference leg is not being maintained filled by tb condensing pot.

7 c. Conclusions

i

The inspectors discussed with the licensee the licensee's interpretation

of TS 3.3.1.1 which allows bypassing / tripping of two of four instruments

' in the same protection set. The inspectors are continuing to determine

'

if the licensee was correctly interpreting TS 3.3.1.1. This issue is

identified as Unresolved Item (URI) 50 327. 328/96 09 01. Determine

2

Whether TS 3.3.1.1 Allows One Pressurizer Pressure Channel to Be

'

. Bypassed at the Same Time that a Second Pressurizer Pressure Channel is

Tripped.

The inspectors noted that during the backfilling evolution that a

portable high 3ressure pump was used to backfill the reference leg. At

times during tie evolution the pump was exposed to RCS pressure. The

inspectors considered that this evolution presented a potential safety

hazard to personnel and could result in a breach of the RCS.

03 Operations Procedures and Documentation

03.1 Uncontrolled Guidance Found in Main Control Room (MCR) (71707)

i

'

a. Insoection Scope (71707)

On August 15. 1996, the inspector conducted a review of engineering

documents availab'.e for operator use/ reference in the MCR.

b. Observations and Findinas

The inspector noted that two binders containing miscellaneous

information from the engineering group were in the MCR. A binder in the

Unit 1 area was marked " Assistant Shift Operations Supervisor (AS0S)

Letters of Interest." It contained 38 different documents providing

information and guidance to operators. These included memoranda, single

pages of information with an engineering signature Technical Su) port

Investigation Requests (TSIRs), and portions of PERs. Some had land

written notes. One Unit 1 Senior Reactor Operator (SRO) indicated that

they might operate in accordance with this guidance, however, they would

not operate outside of procedures. In the Unit 2 area the binder was

marked "TSIR, Action Plans". The licensee somet.imes develops Action

Plans to direct activities to be performed to address problems noted in

_

__ _- _ _ ._

, .

. .

-

,

,

5

3

'

TSIRs. The Unit 2 binder contained various documents similar to the

'

Unit 1 binder although, no Action Plans were in the book. Information

was organized by system in this binder.

4 c. Conclusions

The inspector noted that these documents appeared to have no attendant

controls by operation's management to evaluate whether the guidance was

to be followed, whether the information was current, whether a Shift l

Order or Standing Order was appropriate, and to assure consistent

information was given to operators. The inspector considered this to be

a weakness in control of information to operators. This observation was I

.

discussed with licensee management.

.

03.2 Lnoggroole Emeraency Gas Treatment System Train (EGTS)

a. Insoection ScoDe (71707)

Inspection Report 50 327,328/96 08 identified an unresolved item (URI)

50 327/96 08 01, which discussed a mispositioned switch in the EGTS on

July 24,1996. The mispositioned switch rendered the EGTS train

inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 43 minutes. Further review of the post

4

maintenance and operational procedures, in addition to a review of the

corrective actions in the associated PER, were conducted.

<

b. Observations and Findinas

Initial reports indicated that both trains of EGTS were inowrable

during this event. However, further review noted that, altlough the "B"

,

'

train was administratively inoperable because management review of the

testing had not been completed, the system was aligned and capable of

performing its safety function. This precluded the system from being

inoperable according to TS and eliminated the potential TS 3.0.3 entry.

'

The inspectors noted that the operators had placed control switch 1 HS-

65-10 in the wrong position and also had improperly and independently

verified the switch in the wrong position. Following a detailed review

of the procedure, the inspectors concluded that the operator actions

were the result of an inadequate procedure. While the procedure

specified the final damper position, it did not specify the final switch

, position.

The inspectors also noted that the majority of safety related control

4

room control switches, spring return to their safety po itions, however,

i not all of the switches associated with the EGTS spring return to their

safety positions. For these switches additional procedural guidance

would be warranted to ensure proper positioning.

.

. _ . __ _ _

, -

. .

-

.

6

c. Conclusions

The placing of the EGTS control switch in the wrong position, which

rendered the "A" train of EGTS inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 43 minutes, is

a violation of NRC requirements. The operator, who mispositioned the

control switch, identified the error during shift turnover and promptly

reported the error to shift management. Subsequently, the licensee has

identified 5 procedures which do not adequately control hand switch

configuration. The deficient procedures have been or will be revised

prior to future use. Based on the operator's )rompt reporting of this

error and the corrective actions detailed in PER SQ962041PER, 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 (NCV 327/96 09 02).

08 Miscellaneous Operations Issues

08.1 Proposed Technical Soecification Chanae Reaardina Normal Work Day

a. Insoection Scope (71707)

During this ins ction period the inspectors reviewed the licensee's

established wor,,ing hours, as described in TS 6.2.2, Facility Staff.

b. Observations and Findinas

TS 6.2.2.g (working hours of unit staff who perform safety related

functions) states, in part, that the objective shall be to have

'

operating personnel work a normal 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> day, 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> week while the

unit is operating. Since the last refueling outage (U2C7) which ended

in the Spring of 1996, SR0s have worked a 12-hour rotating shift while

Reactor Operators (RO) and Assistant Unit Operators (AU0) have worked an

8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift.

The licensee agreed with the inspector that the current TS wording

.

'

does not accurately reflect the current, or possible future, shift hours

worked by operations personnel. As a result, on August 19, 1996, the

licensee initiated a TS amendment which will be worded to more clearly

reflect the normal work shift hours for operations personnel,

c. Conclusions

The inspector concluded that this proposed TS change was administrative

in nature and that the licensee has been in compliance with the

guidelines of TS 6.2.2.g regarding use of overtime,

e

. _ _ _ _

, .

,

.

7

II. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments (62703)

a. Inspection Scoce (61726 & 62703)

The inspectors observed and/or reviewed all or portions of the following

work activities and/or surveillances:

e 2 SI-SXV 003 219.0 Auxiliary Feedwater Check Valve Test

During Operation

e 2-SI 0PS 030 286.0 Cumulative Time That Containment Purge

Supply and Exhaust Isolation Valves Are

Open

e 2 SI SXP 003 201.B Motor Driven Auxiliary Feedwater Pump 2B B

Performance Test

e WO9632986 Lube & Inspect Charging Pump and Charging

Pump Speed Increaser

e WO9636019 Install Refurbished Reactor Trip Breaker

in Unit 2.

b. Observatior.s and Findinas

The inspectors noted that the work activities and the performance of

surveillance activities were adequately performed.

c. Conclusions

The inspectors noted that the control room logs, associated with

surveillance 2 SI 0PS 030 286.0, were incomplete. The logs did not

always document the initiation and completion of the various containment

purge evolutions and this was considered to be a negative observation.

M1.2 Observation of Maintenance and Surveillance Activities

a. Insoection Scope (62703)

Maintenance activities were observed to determine if the activities were

performed in accordance with licensee procedural requirements. The

-

-.- . . - . _- - - - . - _ _ . - _- ,- - . - .

o o

.

.

.

.

!

' inspection scope included observation of portions of the following

maintenance activities by a NRC Region II maintenance inspector:

i e WO963502000 Electrical maintenance implementation of relay

4

protection design change of 1C Condenser Cooling

Water (CCW) Pump Motor.

. e WO963548400 Hechanical corrective maintenance on auxiliary

building fire door

i

e WO963534500 Customer Group corrective maintenance to disable

gas operated relay protection and install sudden

. pressure relay protection for Main Bank

'

,

Transformer 1C

[ e WRC336606 Troubleshooting corrective maintenance by the

Fix It-Now team to locate a ground on electrical

panel LC104

e MI 4.2.3/SI 102 Mechanical preventive maintenance monthly

mechanical inspection of EDG 2A A

b. Observations and Findinas

The maintenance activities observed were required to meet the applicable

requirements of Site Standard Practice (SSP) 6.1, Conduct of

Maintenance, SSP 6.2, Maintenance Management System, and SSP 6.25,

Maintenance Management System Performance of Work Orders.

The maintenance activities observed were satisfactorily >erformed. Work

was accomplished per the work documents and the work paccage

instructions were actively in use. Drawing and procedure revisions were

verified prior to use. Personnel qualifications were checked for the

Maintenance Instruction (MI) 4.2.3/ Surveillance Instruction (SI) 102

monthly Preventive Maintenance (PM) inspection of EDG 2A A and the

3ersonnel >erforming the work were task qualified. Personnel were

(nowledgea)1e on the equi) ment and the procedures. Measuring and Test

Equipment (M&TE) was checced and verified to be in calibration. The

pre job briefir9 for WO963502000 was considered good.

During review of the work package for the 2A A EDG monthly mechanical

inspection work activity, the inspector noted a weakness in EDG

trending. Procedure MI 4.2.3 obtains cylinder exhaust temperature data

for trending purposes. The procedure requires that adjacent cylinder

exhaust temperature differential be s 100 degrees F. Turbocharger inlet

temperature differential was required to be s 200 degrees F. If the

cylinder exhaust temperature differential exceeds 100 degrees F or

turbocharger inlet temperature differential exceeds 200 degrees F then a

work request is required to be initiated for resolution. If a WR

already exists, then the procedure requires that the WR number be

recorded in the procedure.

.- - --- . . . . .

. - , - .. - .- -- - - -

, .

.

.

..

,

9

The inspector determined that cylinder No. 7 was reading 660 degrees F

' and the remaining cylinder temperatures ranged from 940 1000 degrees F.

Existing WR 201222 written in June, 1995, documented this condition on

engine 2A1 cylinder No. 7 and a condition of high turbocharger inlet

temperature differential. Licensee WO 950658600 performed in February

1996, to implement WR C201222 determined that engine 2A1 turbocharger

and cylinder M. 7 temperature parameters had open thermocouples or

thermocouple wiring.

The cylinder exhaust temperatures were recorded for trending purposes to

monitor engine performance. Low cylinder exhaust temperature readings

or high cylinder exhaust temperature differential values could be due to

failed indication circuitry or could be an indication of performance

problems with the cylinder. High turbocharger inlet temperature

differential could be due to failed indication circuitry or governor

performance problems. The exhaust gas and turbocharger inlet

temperature values were not utilized as part of EDG operability

verification.

Discussions with licensee technical support and maintenance personnel

indicated that while the temperature measurement conditions existed

since June 1995, no attempt was made during the monthly inspections to

utilize compensatory measures to obtain the data on these two

temperature parameters.

The licensee operated EDG 2A A from June 1995, until February 1996,

without identifying that the problem was open thermocouples or

thermocouple wiring. The licensee operatea EDG 2A A since June 1995,

without utilizing any compensatory measures to obtain the 2A1 EDG engine

turbocharger inlet and cylinder No. 7 exhaust temperature values for

trending. This is considered a weakness in trending and performance

monitoring of the EDG.

c. Conclusions

The maintenance and surveillance activities observed were satisfactorily-

performed in accordance with licensee procedures. A weakness was noted

in EDG temperature parameter trending.

M1.3 Review of Comoleted Work Orders

a. Inspection Scooe (62703)

Selected work orders for completed work activities were reviewed to

determine if the completed work met ap)11 cable procedural requirements

and to determine the degree to which t1e activity was documented in the

work order (W0). The following work orders were reviewed by a NRC

Region II maintenance inspector.

"I

, *

. .

'

.

10

e WO963548400 Hechanical corrective maintenance on auxiliary

building fire door

e MI 4.2.3/SI 102 Mechanical preventive maintenance monthly

mechanical inspection of EDG 2A A

e WO963001700 Chemical and Volume Control System (CVCS) valve

2VLV 62 659 machining

e WO962806000 Non-return valve 2 FCV-005 0037 counter weight

modification

b. Observations and Findinas

A minor documentation error was noted in the work package for the 2A A

EDG monthly mechanical inspection. Procedure MI-4.2.3 requires that a

work request be written if adjacent cylinder exhaust temperature

differential exceeds 100 degrees F. EDG 2A A cylinder No. 7 read 660*F

while the rest of the cylinders read from 940 1000 degrees F. If an

existing work request existed for the condition then the existing WR

number was to be recorded. No work request was recorded and the

inspector considered this an example of lack of attention to detail.

The licensee corrected the work package. The documentation reviewed

showed that except for the item mentioned the work was done according to

the procedural requirements.

c. Conclusions

The level of detail of work documentation was adequate but not thorough.

A minor documentation error was noted in one work order which was

corrected by the licensee.

M1.4 ERCW Discharae Check Valve Stuck Open

a. Insoection Scope (62703)

The insxctors reviewed the licensee's actions related to repair of ERCW

pump L 3 discharge check valve.

b. Observations and Findinas

On August 23, 1996, the licensee identified that the discharge check

valve on ERCW pump L B was leaking by, when the pump was stopped, at the

rate of approximately 3000 gallons per minute (gpm). The licensee

subsequently determined that the swing arm of the valve exhibited

excessive wear which resulted in the valve not properly seating. The

licensee also discovered that the valve had been incorrectly installed

approximately two years ago. The inspector determined from the valve

vendor's manual that the valve had in fact been installed incorrectly.

Further discussions with the system engineer revealed that it could not

be concluded that the incorrect installation resulted in the valve

- _ _ _

. .

,

.

11

failure. The valve was repaired and returned to service. The licensee

initiated Problem Evaluation Report (PER) No. SQ962283PER to document

the valve failure,

c. Conclusions

The inspectors concluded that the ERCW check valve had been installed

incorrectly at some time in the past, but could not conclude that the

incorrect installation resulted in its subsequent failure. The licensee

plans to inspect the remaining seven ERCW discharge check valves at a

future date. The corrective actions associated with the PER will be

reviewed during a future inspection. This item is identified as

Inspector Followup Item (IFI) 50-327, 328/96-09 03, Review Corrective

Actions Related to ERCW Check Valve Failure, PER SQ962283PER.

'

M2.3 Eauioment Material Condition and Reliability Issues

a. Insoection Scope (62703)

The inspectors noted that during shift relief / turnovers, the morning

status meeting and while reviewing operator logs that a variety of

systems and components appeared to be experiencing repetitive / multiple

failures. A detailed review of the control room logs and site

'

information reports (morning status meeting) was conducted, to identify

those systems / components with multiple deficiencies. The operations

logs and status reports covered the period from July 28 through

September 14.

. b. Observations and Findinas

The operations logs, although not always detailed, provided the majority

J of the examples documented in the following section. The individual

descriptions were taken from the unit operations logs or the site

information re) orts and a detailed review of each item has not been

performed by t1e NRC. The operations logs indicated that many of the

items were corrected in = ti..aly manner. While this list was intended

4

'

to document the quantity and types of problems being experienced, it

also was intended to focus on systems with recurring failures / problems.

The following are examples of equipment failures / problems noted during

the period, however, note that this list is not all inclusive.

e Various EDG starting air system relief valves were found relieving

eight times (Section E4.1),

o At one point, only one of four primary water pumps was available

to supply both units due to excessive seal leakage and vibration

problems.

s

e Only one of four shutdown board room cooling fans was available

due to a loss of freon from one chiller unit (two fans inoperable)

. and high vibration on one of the other fan units.

.__ __ _ _ . _ . _ . _ _ _ _ __ .. .- _ . __ _ _ _ _ _ _ _ _ . .. _

.- .

.

.

! ,

i 12

) e Various reactor coolant pump (RCP) seal leakoff detectors (3 of 8)

- became stuck; twice during the inspection period, with a third

j occurrence just following the completion of this inspection

period.

? e The glycol chillers experienced multiple problems: on July 31, the

l- "E" chiller had excessive vibration; on August 8, the "A" chiller

was found tripped, on August 15, the "A' chiller tripped due to

air in the system which could not be removed: on August 20, after

l filling and venting the "I" chiller, the operators could not keep

it running; on August 20, maintenance replaced the "I" chiller

i control module due to shorting; on August 21 all of the chillers

i and pumps tripped due to low ex

o)erators could not get the "D"pansion tank level; on August 21, chiller t

i t1e "H" chiller tripped for no appartnt reason and could not be

i restarted, in addition, "there were no spare chillers available";

! and on September 11, the "E" chiller was taken out of service for

i troubleshooting.

L

! e The boric acid system experienced problems with flow oscillations,

j tripping thermal overloads, and slow controller operation.

i

e The main turbine oil systems ex)erienced problems with low turbine

i Auto Stop 011 pressure and low 91C pressure.

l. -e There were multiple leaks from the ERCW hypochlorite system: the

i 2A header on August 2, the 1A header on August 3, the IB header on

! August 17, the 2A header on August 20, the 1A header on August 25,

. the 1A relief valve was found lifting on August 27 and the "A"

i skid discharge piping had a leak on September 9. 'In addition, on

September 1, the supply breaker for the injection pumps kept

j tripping,

e .The Control Rod Drive Motor (CRDM) automatic temperature control

l cooling valves were drifting closed and sometimes caused the fan

cooling supply air to exceed the administrative limits of 110

i degrees F.

1

! e There were various computer problems during the period such as:

the Integrated Control System (ICS) computer system had not been

l able to calculate core burnup since the system was installed; a

i digital link to the ICS computer for point U1118 failed causing an

4 indicated increase of 10 Megawatts Thermal (MWT) to the total

power calculation; and the ICS com> uter calorimetric readings have

failed due to a failed input from ) lowdown flow.

l

L e The station air compressors had multiple problems: on August 9,

l the "D" compressor had a blown gasket on the top of the

intercooler; on August 20, the "D" compressor inner cooler relief

~

i lifted too much to stay in service: on August 20, the operators

noted that the "A" compressor was in lead but only half loads, the

"C" compressor trips on high discharge pressure and the "D"

'

l

l

> _. . -.

. _ _ - _ - - _ . _ _ ___

. .

.

.

'

.

13

compressor had a stuck ERCW rotometer/or flow blockage to the

t

compressor; when released from clearance on August 22, there was

no ERCW flow to the "D" compressor: on August 23, the "D"

compressor was removed from service because its intercooler relief

valve was lifting; on August 23, when "D" comaressor was placed

back in service, the post maintenance test (pit) was unsuccessful

t,ecause air was blowing out the side plate on the compressor; on

August 24, a work request was written on the "C" control air

,

prefilter due to high filter differential pressure (DP): and on

August 24, operaters tagged out the "D" compressor.

e On August 13, Unit 2 roc'3 auto stepped "out" with no signal (8:00,

8:05, 11:04, and 11:09 a.m., and 12:11 p.m.). On August 16. Unit

I rods stepped "in" for no apparent reason. On August 17, Unit 2

rods stepped "in" for no apparent reason at 2:03 p.m., and

3:07 p.m. On August 18, Unit 1 rods stepped "in" for no apparent

reason.

,

e On August 23, Unit 2 loop calculation processor (LCP) card failed.

Shortly after the card failure, a steam dump failed open when the

a steam dumas were placed in the " pressure mode". On September 10,

a Unit 1 _CP card failed. A replacement card was not available

and the unit had to remain in a degraded condition until a

replacement card could be found.

! e The 161 and 500 kv switchyard cable tunnels were flooded with

several inches of water. The permanent

and the temporary pump had been removed, pumps were not operable

e On Unit 2, 3 of 4 steam generator blowdown sample valves will not

,

open.

l Several of the problem areas listed above were also included in

i IR 50 327,328/96 08, Section M2.3, Equipment Material Condition and

Reliability Issues, and included the EDG air starting system, the

-

station air compressors, a protection set card and the containment

chillers.

i c. Conclusions

The listed examples indicate weaknesses in plant material condition.

The repetitive problems caused added operator burden (work arounds).

Such as: increased monitoring of the EDG starting air receivers; manual

o>eration of the EDG starting air compressors; and special monitoring of

t1e CRDM cooling supply valves. The multiple failures impacted

maintenance resources in correcting the problems and operations

resources for switching and tagging and equipment status control.

Examples such as the stuck RCP seal leakoff detectors, automatic rod

1 stepping, and failed LCP cards impacted day to day operations. These

are indicative of weaknesses in maintenance and engineering support.

a

. . . _ _ _

, a

.

.

'

.

14

,

M2.4 Review of EDG Governor Booster Cylinder Corrective Actions

a. Insoection Scope (40500)

The inspector reviewed the corrective actions for a previous EDG

governor booster cylinder failure to determine if corrective actions

were adequate,

b. Qbservations and Findinas

NRC Inspection Report 50 327,328/96 02 described the circumstances of a

, failure of the EDG 1A1 governor booster servomotor. The booster

servomotor was replaced and the failed unit was sent to the vendor for

failure analysis. The licensee also evaluated the failure at their own

independent laboratory.

The licensee determined that no PM existed for replacing governor

booster servomotors. The governor booster servomotor which failed had

been in service for approximately 20 years. A 12 year PH was submitted

by the technical support engineer to establish a governor booster

servomotor replacement interval.

The inspector reviewed the failure analyses wrformed by the vendor and

the TVA lab. The vendor concluded that the moster had exceeded its end

of bfe and the booster piston seals were worn due to normal aging.

Greasy debris and rust particles were also observed to be restricting

the cylinder air ports. The inspector discussed the failure analyses

with technical support personnel and determined that the rust particles

were probably due to system piping corrosion which occurred prior to the

use of system air dryers. Oil side leakage past the cylinder seals

could have contributed to the air port fouling. The inspector verified

by plant walkdowns that the air lines to the governor servomotors were

upstream of the air line lubricators. The inspector determined that the

licensee had evaluated the findings of the two fadlure analyses reports

and was taking action to address these findings.

c. Conclusions

The licensee's corrective actions for the EDG governor booster

servomotor failure was satisfactory.

M3 Maintenance Procedures and Documentation

M3.1 Review of Steam Generator Documentation

a. Inspection Scope (73753)

The inspector reviewed procedures, programs, and records associated with

the condition of the Sequoyah Steam Generators (SGs) to determine if the

licensee met FSAR commitments. (This review was the ccmpletion of an

inspection initiated July 8 12, 1996, and documented in Inspection

Report 50 327,328/96-08. Paragraphs M2.2 and M6.1)

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

,

,

,

.

15

,.

b. Observations and Findinas

Two SG areas which have historically contained tubing materials with

high residual tensile stresses, and therefore susceptible to stress-

'

related cracking

i the tube bunfle, problems, are the

and the inside tight radius

surface bends where

of the tubing in rowsit 1was and 2 of

explosively expanded against the tube sheet. The licensee has attempted

<

to reduce, or eliminate, the tensile stresses in these areas of the SGs

3

by: heat treating (stress relieving) the tubing in the tight radius

bends; and by peening the inside surface of the tubing in the tube

sheet, to change the surface condition of the material from residual

tensile stresses to residual compressive stresses.

,

The inspector selected the heat treatment of the Unit 2 SGs as a sample

of this >rogram to review. The review included the Westinghouse Field

Service )rocedure STD FP 1993 6558. Rev 1, dated 4/28/94, "Se

i Unit 2 (TEN) Model 51 U bend Heat Treatment Field Procedure"and quoyah

individual tube heat treatment records for the work done.

The inspector also reviewed material heat numbers and subsequently the

chemistry and physical properties of the Unit 2 SGs tubes which have

been plugged.

c. Conclusions

Steam Generator records indicated that the licensee had implemented a

<

comprehensive program to minimize stress related degradation of SG

tubes.

M6 Maintenance Organization and Administration

! M6.1 Manaaement Involvement in the Steam Generator Proaram

'

a. Insoection Scooe (73753)

The inspector reviewed documentation and held discussions with licensee

personnel concerning management involvement with the SG program.

. b. Observations and Findinas

'

The inspector reviewed the current five year plan for SG inspection and

maintenance. During this review the licensee discussed their )lans for

'

requesting licensing approval for the repair of degraded SG tu>es by the

use of laser welded sleeving. This repair method will also be used as a

contingency method for recovery of previously plugged tubes.

A discussion was held with licensee engineering aersonnel concerning the

, fact that SG management is currently working wit 1 a 5% plugging limit on

the SGs. The explanation offered .was that in the past, TVA had not

contracted for a more rigorous accident analysis to justify a higher

plugging limit. The licensee went on to explain that TVA had recently

changed nuclear fuel vendors, and as a part of the analysis of the new

_

. -

_ _ _ _ . _ . . . _ . _ _ _ _ _ . . _ . _ .-_____- - -._. --

,

'

, .

.

.

m

i

l 16

fuel, TVA had requested an accident analysis which would support a 15%

plugging limit on the SGs.

The inspector, and licensee SG management personnel, also discussed the

licensee's rationale for not lowering T to protect the SGs. The major

reason for not reducing Tu appearsto$t the significant revenue loss

from the resulting power reduction.

c. Conclusions

The licensee's SG organization has done a very good job of reviewing

their inspection and repair options, and soliciting plant and corporate

management support for the options selected.

MB Miscellaneous Maintenance Issues

M8.1 (Closed) Licensee Event Report (LER) 50 327/95014, " Failure to Properly

Identify and Plug a Steam Generator (SG) Tube that was Determined to

Exceed the Technical Specification Plugging Limit."

(Closed) Licensee Event Report (LER) 50 328/96002, " Failure to Properly

Identify a Steam Generator (SG) Tube that may have Exceeded the

Technical Specification Plugging Criteria."

The similarities between these two events is that the defects in

question were caused by degradation mechanisms expected in these SGs,

and that in each case, two independent analyses missed the defects.

The licensee's corrective action for LER 50 327/95014 included the

addition of dented intersections with flaws to the )erformance data base

used to train and qualify eddy current analysis. T1e corrective action

for LER 50 328/96002 included the addition of Rows 1 and 2 U bends with

severe permeability variations in the performance data base, and an

update to the Steam Generator Analysis Guidelines, to enhance

permeability variation effects in the U bend regions.

The inspector reviewed the August 1996, revision of the Steam Generator

Analysis Guidelines and verified that permeability variation effects had

been enhanced. The inspector also reviewed a demonstration of the

licensee's performance data base, which included the Row 1 U bend with

severe permeability which had been the subject of LER 50 328/96002.

The problems identified in the LERs constituted two examples of licensee

identified violations of the 31 ant technical specification definitions

for SG operability. The two .ERs are considered to be two examples of

one violation because the violation reported in LER 50 328/96002 had

already occurred when the violation reported in LER 50 327/95014 was

discovered, and the increased sensitivity to that type of problem led to

the second discovery.

The TS violations descrioed in the LERs meet the criteria for a licensee

identified, non cited violation, as described in Section VII.B.1 of the

,

- - -. - -.

a. ,no,. .s u aa uu,..m.m.a- m ..na. a ~n , . , . . , w. .p w.s . a - , . ..,~..an... aus-..as.--ws-~..ae .w

. se, -~a a-,s...n-u n.a s - .r a , ,s.u. a .ss--s a s a. s w x

.

.

,

.

'

4

17

i NRC Enforcement Policy. This will be reported as NCV 50 327,328/96 09-

04, " Failure to Identify Steam Generator Tube Defects Which Were u

!

Excess of TS Plugging Limits."

i

'

III. Enaineerina

El Conduct of Engineering

E1.1 General Comments (37551)

During the inspection period, TVA finalized the reorganization of sita

staffing. Discussions with engineering indicated that the system

engineering department /section was significantly affected. Seventeen of

forty nine )ositions were left unfilled / vacant. In additien, some

engineers clanged positions and responsibilities. Engineering plans to

fill the positions as soon as appropriate personnel are identified.

E2 Engineering Support of Facilities and Equireent

E2.1 Review of Licensee Evaluation of Potential for Incorrect Material

Received From Vendor

a. Insoection Scooe (37551)

On June 21, 1996, the licensee received a request for assistance letter

relating to a 10 Code of Federal Regulations (CFR) Part 21 Evaluation

for material received from Consolidated Power Supply. The material

included 3/4" schedule 80 pipe which may not have been the ty)e

specified on the purchase order. The inspector reviewed the ' art 21

informaticn, PER SQ961874PER, which was written to evaluate the

condition.-and the corrective actions associated with the issue,

b. Observations and Findinas

The initial licensee engineering evaluation for PER No. SQ961874PER was

reviewed by Region II specialists during the week of July 8 12, 1996.

The licensee stated they received a shipment of the sus.nect material

under Contract Number P 95N2J 148011 000. The licen a determined that

the material was used in different plant applications; however, the only

technical concern for material received was associated with weld

processes used if the material was not as specified in the contract.

The licensee initially determined that no safety related applications

were involved in the use of the supplied material which involved

welding. The Region II inspectors noted that the weld process used by

the licensee may have been ina)propriate for materials supplied and

could result in cracking, breating, or failure.

During this period, the inspector conducted additional review of the

issue. The inspector met with licensee engineering personnel and

discussed the concerns associated with potential welding applications.

i

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

-

.  :

• l

.

.

l 18

i l

Over the next two weeks, the licensee conducted additional testing of

the materials received from the vendor. Testing of samples of piping

from the five pieces received from the vendor under Contract Number P-

,

95N2J 148011-000 determined the piping was as specified in the contract.

,

c. Conclusions

! The inspector concluded that after identification of initial concerns

based on the engineering evaluation for the Part 21 potential problem,

j the licensee took appropriate positive actions to determine the issue

l did not affect Sequoyah.

i

E2.2 Review of Status of Unit 1 Samole System

!

a. Insoection Scope (37551)

i

On August 2,1996, the inspector conducted a walkdown of a temporary

! system installed on Unit 2 for drainage from steam generator blowdown

sample drains in accordance with Temporary Alteration Control Form

(TACF) 2-95 0012 043. The inspector revicwed the associated

-

. documentation supporting the TACF, and also conducted a walkdown of the

l Unit 1 hot sample room to evaluate the condition of the Sample System in

l this area.

f

j b. Observations and Findinas

i

j The inspector verified the proper installation of the temporary

4 alteration. During the review, the inspector noted that several sample

'

valves on c panel associated with sampling of boron injection tanks .

4

(BIT), appeared to be in poor material condition. Past leakage was  ;

! obvious on several of the valves based on coatings of boric acid.  !

9

'

Further review of this issue determined that this portion of the sample '

system was not being used. The inspector noted that there was no l

.'

documentation that abandoned this mrtion of the sample system. The '

system engineer wrote PER SQ962182)ER for determination of whether these

sampling lines need to be formally abandoned. The ins wctor noted that

4

proper valve status control was being maintained for t11s portion of the

sample system.

i c. Conclusions

i The inspector concluded that the temporary alteration in the Unit 2 hot

< sample sink room was installed in a satisfactory manner and the safety

assessment justified the installation. However, the inspector noted

that sample valves located in the Unit I hot sample room for the Safety

Injection system were in poor material ccndition and presented potential

housekeeping problems. In addition, this portion of the sample system

was not formally abandoned. The poor material condition of the valves

and the informal control of abandoned equipment were considered to be

negative observations.

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

. .

.

.

.

19

E2.3 Unit 1 Residual Heat Removal System (RHR) Gas Accumulation

a. Inspection Scoce (37551)

'

The inspectors reviewed the results of the Unit 1 RHR gas accumulation

data which the licensee calculated during the American Society of

Mechanical Engineers (ASME)Section XI tests on August 29, 1996 (A-

Train) and September 5, 1996 (B-Train). The inspectors compared the

data with previous gas accumulation data and reviewed the licensee's

corrective actions for the gas accumulation problem. Previous reviews

of the RHR gas accumulation issue were discussed in IPs 50 327,328/95-

04, 95-06, 95 12, 96-01, and 96 08 and in Licensee Event Report (LER)

50 327/95001.

.

b. Observations and Findinas

In November 1995, the licensee added Tracking and Reporting of Open

Items (TROI) Action Item Number 29 to PER No. SQ950029PER. That PER was

the original PER, initiated in January 1995, which dealt with the RHR

gas accumulation. Action Item 29 required the licensee to " Develop

. methodology for evaluating the gas void momentum effect on RHR injection

'

piping loads. Determine relationship of the piping void size to pipe

loading and establish maximum allowable void size based upon piping

, structural margins."

"

In January 1996, an independent contractor com)leted a study of the

Sequoyah RHR gas accumulation issue. One of t1e long term actions from

that study stated that if too much gas was present, it could interfere

with or delay delivery of low pressure injection in accident conditions

and that the limit (maximum gas accumulation volume) should be

determined by TVA and Westinghouse Accident Analysis.

In March 1996, the licensee established 8 cubic feet as the maximum

, allowable void size in the RHR system. The decision to use 8 cubic feet

'

as the limit was based upon the known gas volume in the RHR system at

the time and not upon a formal engineering analysis of the structural

limits of the RHR system. The licensee concluded that since 8 cubic

feet was known not to cause water hammer damage to the RHR system that

it was reasonable to use 8 cubic feet as the maximum allowed limit and

thus close the TROI action 29 based upon that assumption. However, the

closure of action item 29 stated that the void size of 8 cubic feet

could not be relaxed.

On August 29, during an ASME Section XI test on the RHR 1A-A pump, the

licensee calculated the gas volume to be 11.6 cubic feet. On August 30,

1

1996, in response to the identification of 11.6 cubic feet of gas, the

licensee completed another engineering evaluation to determine the

maximum allowable gas accumulation. The new evaluation referred to the

previous 8 cubic feet limit as an administrative limit and revised the

gas accumulation limit to 15 cubic feet. Again, the evaluation was

'

based upon the known history of gas build up rate and not upon a formal

engineering evaluation. The evaluation stated that the average gas

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

,

, 1

.

.

.

20

-

accumulation rate since January 1996, has been approximately 4 cubic

feet per quarter. The evaluation assumed that 4 cubic feet was

indicative of the accumulation rate in the past and that as much as 24

cubic feet of gas (4 cubic feet per quarter x 6 quarters per operating

cycle) had been present, prior to the current practice of quarterly

venting, during previous quarterly Section XI pump testing and had not I

resulted in water hammer damage. The licensee concluded that since 15

cubic feet of total gas accumulation was significantly less than the

total volume of gas expected to accumulate for a full fuel cycle (24

cubic feet), the associated pipe movements would not be sufficient to

cause pipe support failures or challenge the integrity of the piping

pressure boundary.

2

On September 5, 1996, during a Section XI test on the RHR 1B B pump, the

gas volume was determined to be 13.8 cubic feet. Following the

identification of 13.8 cubic feet of gas, the licensee reevaluated the

limit of 15 cubic feet which had been established on August 30. On

September 6, using the same methodology as was used on August 30, the

licensee reestablished the maximum. gas void limit at 22 cubic feet.

It should be noted that the gas accumulation calculations on August 29

.

and Seatember 5, were performed after the RHR system had been vented and

that t1e licensee did not measure the volume of the vented gas.

Therefore, the calculated gas accumulation of 11.6 and 13.8 cubic feet

represented the "as left" gas accumulation in the system.

.

As discussed in Inspection Report 50 327, 328/96 08, the licensee plans

to install a continuous venting modification during the next two

refueling outages,

c. Conclusions

The inspectors were unable to conclude whether the licensee's method of

determining the maximum allowable RHR gas accumulation, to preclude

i water hammer damage, was acceptable. Pending the resolution of this

issue, this item is identified as URI 50 327, 328/96 09 05, Determine

l Whether the Licensee's Method of Determining the Maximum Permissible RHR

Gas Void Size is Acceptable.

The inspectors concluded that licensee's practice of venting the RHR

system prior to calculating the volume of gas in the system did not

provide an accurate representation of the total amount of gas in the RHR

system.

E2.4 Unit 2 Core Flux Tilt

a. Insoection Scoce (37551)

During the inspection period the inspectors were informed of a Unit 2

,

'

core flux tilt and of potential plans to reduce axial flux difference

(AFD) limits if subsequent flux maps identified additional reductions in

margins.

_.

.- - . . .- - - .

, , .

.

.

-

.

21

b. Observations and Findinag

i

After noting the flux tilt problem in Unit 2, the inspectors discussed ,

the condition with site reactor engineering personnel. Engineering '

noted that the unit 2 core tilt had developed following the refueling

outage in May 1996 and that the tilt had increased to almost 3%. A

,

specific reason for the tilt could not be identified. At the completion

of the inspection period the tilt had decreased to approximately 1.7%.

The inspectors discussed the tilt condition with NRC Region II and

headquarters personnel.

Subsequent discussions with control room operators noted that some of

the operators had not been aware of the tilt condition until the AFD

limits had been reduced. The inspectors noted that the control room

indications such as delta T and Tave did not identify a tilt condition.

In addition, the inspectors noted that the computer printout for tilt,

did not indicate a tilt condition. Discussions with engineering

indicated that following a flux map, the nuclear instrument inputs are

normalized which eliminates the actual tilt indication. Discussions

with the region and with other utilities noted that this was a standard

practice.

c. Conclusions

It was determined that while the tilt condition was somewhat unusual,

the licensee was properly monitoring the condition and had taken

appropriate actions. However, engineering did not clearly communicate,

to operations personnel or to the resident inspectors, the fact that a

tilt condition existed in the Unit 2 core for an extended period of time

following discovery. Although not reportable or safety significant, the

lack of prompt communication is being noted as a negative observation.

E4 Engineering Staff Knowledge and Performance

E4.1 Imorocer Emeraency Diesel Generator Startina Air System Operation

a. Insoection Scooe (37551)

The inspectors reviewed various documents and historical records to

determine why the EDG starting air compressors were causing their relief

valves to lift and causing the low pressure alarms to alarm. The

documents included the control room logs, EDG starting air system

corrective maintenance history, EDG design basis document FSAR section

containing the EDG starting air system, and the operator rounds logs.

In addition, the inspectors interviewed the system engineers, auxiliary

operators, and control room operators and observed system operation in

manual and in automatic.

l

- -- -- -,--- _-- - . - . - . - . _ , . - - - . - - ,

. =

-

.

,

'

.

i

22

l

j b. Observations and Findinas

During the inspection period, the inspectors noted that the control room

j

logs were documenting instances when the EDG starting air compressors

2

were found with their relief valvas lifting or when the low pressure

alarms were in alarm. In addition, while observing outside AVO duties,

the inspe W r observed the 2-B 2 EDG staring air receiver relief valve

' ne receiver tank pressure was at approximately 343 psig and

'

lifting. ,

, the compressor was still running although the normal system operating

pressure band is 250-300 psig.

The inspectors discussed the improper operation of the EDG starting air

. compressor control circuitry with the system engineering technical

l support staff. The engineers stated that the root cause of the

i

compressor misoperation was two fold: (1) o)erations was cycling the I

. control switches when routinely (per shift) alowing down the air lines,

j and (2) due to the compressor dryer timer which could cause the

i

compressor to run for up to 5 minutes after reaching shutoff pressure.

Corrective actions were already in place for eliminating the air line

blowdown requirement and the dryer timer issue was under review.

The ins)ectors observed actual operation of the air compressors and

noted tlat it took approximately 20 minutes to increase system pressure

from 270 psig to 300 psig and concluded that an additional 5 minutes '

would not have caused the pressure to increase to the relief valve

setpoints. The inspectors then interviewed approximately 10 AU0s and a

few control room operators and concluded that blowing down the air lines

almost never caused the compressors to start unless already at the low

pressure automatic start setpoint.

A detailed review of the control room logs noted that various relief

valves had been found lifting on July 23, August 1 and 3, twice on

August 23, and September 8, 9 and 10. In addition, the low pressure

alarm was noted on August 4 and September 10. The inspector noted that

the control room logs did not identify which specific valve was lifting

and it appeared that system engineering was not aware that the receiver

tank / system relief valves were lifting on occasion. It appeared that

the engineers had assumed that only the compressor reliefs had been

lifting.

The inspectors reviewed the corrective maintenance history for the

compressor control switches. All of the switches had been replaced

(modification) in late 1993 due to previous failures. Following

replacement there were five recalibrations due to setpoint drift and

eight replacements. In two cases, switches replaced in 1995, failed

again in 1996 and in one case, a switch replaced on August 1, failed on

August 3 and again on September 9. It was also noted that the switch

problems were being encountered only during summer months.

After additional relief valve lift problems in September and open

discussions with operations during the Plan of the Day meeting,

engineering determined that the control switches were sticking due to

_ _ _ _ _. ._.

. .

.

.

.

23

being temperature sensitive and plans were under development to replace

the faulty switches.

c. Conclusions

,

The ins)ectors concluded that the licensee's efforts to resolve the

faulty EDG starting air comaressor control switch problem to be l

, inadequate and untimely. T1e failure to promptly identify and correct

conditions adverse to quality, is a violation of the licensee's

corrective action program as required by 10 CFR 50, A)pendix B,

Criterion XVI, Corrective Action, and as implemented )y SSP-3.4

'

(VIO 50 327, 328/96 09 06).

In addition, the root cause determination for the initial failures was

1 also considered to be inadequate and is considered to be a weakness.

This ultimately led to multiple challenges to starting air system

integrity (reliefs lifting).

,

E.7 Quality Assurance in Engineering Activities I

~i

E7.1 Updated Final Safety Analysis Report (UFSAR) Review

i

A recent discovery of a licensee o>erating their facility in a manner

contrary to the UFSAR description lighlighted the need for a special

.

focused review that compares plant practices, procedures and/or

4

parameters to the UFSAR descriptions. While performirg the inspections

-

discussed in this re) ort the inspectors reviewed the applicable

portions of the UFSAR that related to the areas inspected. The

, inspectors verified that the UFSAR wording was consistent with the

4

observed plant practices, procedures and/or parameters.

1

IV. Plant Support

1

! F1.1 Review of Transient Fire Loadina (TFL) Conditions

a. Insoection Scooe (71750)

During the week of July 8 12, 1996, an NRC inspector questioned a

condition associated with a TFL Permit TFL 95 0254 which was issued for

i the storage of 1500 pounds of cloth / rubber / plastic radiation arotection

clothing on Elevation 690 between column lines A4 and A6 in t1e

Auxiliary Building. After the issue 4 .dentified, the licensee wrote

. PER SQ961962PER on July 12, 1996. DL< y this period, the inspector

reviewed the licensee's interim actions associated with the issue.

1

b. Observations and Findinas

.

'

On July 30, 1996, the inspector reviewed the status of the licensee's

interim actions. He conducted a tour of the area in the Auxiliary

Building and noted that radiation protection clothing was still being

1

7 *

1

j

-

.

.

24

stored in this location. He also noted Permit TFL 95 0254 dated i

November 14, 1995, was still posted in the area. After the tour, the

'

inspector questioned the licensee about the observed conditions, and

requested appropriate justification for the transient fire loading

condition. On July 31, 1996, after additional review by licensee

engineering personnel, the licensee determined that the location being

used to store the radiation protection clothing had been included under

a deviation for compliance with 10 CFR 50, Appendix R as a low l

combustible area. Although a portion of the clothing had been removed

after July 12, the licensee had not initiated a new transient fire load

permit to justify the observed condition on July 30. The licensee took

immediate action to remove the remaining radiatico protective clothing.

The inspector verified that remaining pre Oive clothing was removed I

from the Auxiliary Building area.

c. Conclusions

The inspector concluded the licensee did not take adequate

im m diate corrective actions for this transient fire load issue

identified during the week of July 8 - 12, 1996. Appropriate

corrective action was only taken after the NRC commenced

additional review of the issue on July 30, 1996. This issue will

be further dispositioned as part of a special inspection

documented in Inspection Report 50 327, 328/96-10.

V. Manaoement Meetinas

X1 Exit Meeting Summary

The resident inspectors 3 resented the inspection results to members of

licensee management at tie conclusion of the inspection on September 17,

1996. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials would be

considered proprietary. No proprietary information was identified.

PARTIAL LIST OF PERSONS CONTACTED

Licensee

• Adney, R., Site Vice President

Brock, D., Maintenance Manager

Bryant L., Outage Manager

• Burzynski, M., Engineering & Materials Manager

Clift, D., Planning and Technical Manager

Driscoll, D., Training Manager

• Fecht, M., Nuclear Assurance & Licensing Manager

Fink, F., Business and Work Performance Manager

• Flippo, T., Site Support Manager

P.-

.

.

.

25 ,

• Kent, C., Radcon/ Chemistry Manager

• Lagergren, B., Acting Operations Manager

• Meade, K., Compliance Manager

Poage, L., Site Quality Assurance Manager

• Rausch, R. . Maintenance and Modifications Manager

Reynolds, J., Acting Operations Superintendent

Robertson, J., Independent Analysis Manager

• Rupert, J., Er gineering and Support Services Manager

• Shell, R., Site Licensing Manager

• Skarzinski, M., Technical Support Manager

Smith, J., Regulatory Licensing Manager

• Summy, J., Assistant Plant Manager

Symonds, J. Modifications Manager

• Attended exit interview ,

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

Effectiveness of Licensee Controls In Identifying, Resolving, &

.

IP 40500:

'

Preventing Problems

IP 61726: Surveillance Observations

IP 62703: Maintenance Observations

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 73753: Inservice Inspection

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

T.yge Ites Number

_ St_atus Description and References

URI 50 327,328/96 09 01 Open Determine Whether TS 3.3.1.1 Allows

One Pressurizer Pressure Channel to

Be Bypassed at the Same Time that a

Second Pressurizer Channel is

Tripped (Section 02.2). i

NCV 50 327/96 09-02 Open/ Inoperable "A" Train of EGTS for 2

Closed Hours and 43 Minutes D* to Operator

Error (Section 03.2).

IFI 50-327, 328/96-09 03 Open Review Corrective Actions Related to

ERCW Check Valve Failure, PER

SQ962283PER (Section M1.4).

NCV 50-327, 328/96 09 04 Open/ Failure to Identify Steam Generator

Closed Tube Defects Which Were in Excess of

TS Plugging Limits (Section M8.2).

I .

l

..

.

.

26

URI 50 327, 328/96 09 05 Open Determine Whether the Licensee's

Method of Determining the Maximum )

Permissible RHR Gas Void Size is

Acceptable (Section E2.3). j

VIO 50 327, 328/96 09 06 Open Inadequate and Untimely Corrective

A tions Associated With the -

Resolution of the EDG Starting Air

Compressor Switch Failures (Section

E4.1).

$ Closed

'

T_.yge Item Ntaber

. Status Description and References

LER 50 327/95014 Closed Failure to Properly Identify and

Plug a Steam Generator (SG) Tube

I

that was Determined to Exceed the 4

Technical Specification Plugging

Limit (Section M8.1). l

l

LER 50 328/96002 Closed Failure to Properly Identify a Steam I

Generator (SG) Tube that may have

Exceeded the Technical Specification

Plugging Criteria (Section 8.1).

LIST OF ACRONYMS USED

AFD -

Axial Flux Difference

ASME -

American Society of Mechanical Engineers

AS0S -

Assistant Shift Operations Supervisor

AVO -

Assistant Unit Operator

BIT -

Boron Injection Tank

CCW -

Condenser Cooling Water

CFR - Code of Federal Regulations

CRDM -

Control Rod Drive Mechanism

EDG -

Emergency Diesel Generator

EGTS -

Emergency Gas Treatment System

ERCW -

Essential Raw Cooling Water

FSAR -

Final Safety Analysis Report

ICS -

Integrated Control System

IFI -

Inspector Followup Item

IP -

Inspection Report

GPM -

Gallons Per Minute

KV -

Kilo Volt

LCP -

Loop Calculation Processor

LER -

Licensee Event Report

MCR -

Main Control Room

MI -

Maintenance Instruction

M&TE -

Measuring and Test Equipment

,,

P ., ,

'

.

27

MWT -

Megawatt Thermal

NCV -

Non Cited Violation

NRC -

Nuclear Regulatory Commission

NRR -

Nuclear Reactor Regulation

PER -

Problem Evaluation Report

PM -

Preventive Maintenance

PMT -

Post Maintenance Testing

PSIG -

Pounds Per Square Inch Gauge

PZR -

Pressurizer

RCS -

Reactor Coolant System

RHR -

Residual Heat Removal

R0 -

Reactor O p rator

RP&C -

Radiological Protection & Chemistry

SG -

Steam Generator

SI -

Surveillance Instruction

SR0 -

Senior Reactor Operator

SSP -

Site Standard Practice

TACF -

Temporary Alteration Change Form

TFL -

Transient Fire Load

T-H0T - Temperature of the Primary Hot Leg

TROI -

Tracking and Reporting of Open Items

TS -

Technical Specifications

TSIR -

Technical Support Investigation Flequest

TVA -

Tennessee Valley Authority

UFSAR - Updated Final Safety Analysis Report

URI -

Unresolved Item

WO -

Work Order

WR -

Work Request

m