ML20140D452

Insp Rept 50-395/97-03 on 970323-0503.Violations Noted.Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20140D452
Person / Time
Site:	Summer
Issue date:	06/02/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20140D419	List: ML20140D413 ML20140D435 ML20140D452
References
50-395-97-03, 50-395-97-3, NUDOCS 9706100387
Download: ML20140D452 (26)

See also: IR 05000395/1997003

Text

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

- .

U., S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket No.: 50 395

License No.: NPF 12

Report No.: 50 395/97 03

Licensee: South Carolina Electric & Gas (SCE&G)

Facility: V. C. Summer Nuclear Station

l

Location: P. O. Box 88

Jenkinsville, SC 29065

Dates: March 23 May 3, 1997 j

i

Inspectors: B. Bonser Senior Resident Inspector

T. Farnholtz, Resident Inspector

D. Jones, Reactor Inspector, RII (Section R1.2)

L. Garner, Project Engineer, RII (Sections 01.1, 04.1 and

R2.1 [ partial], 04.2 and E1.3)

Approved by: G. Belisle, Chief, Reactor Projects Branch 5

Division of Reactor Projects

i

!

!

I

i

I

l

!

Enclosure 2

"

9706100387 970602

PDR ADOCK 05000395

0 PDR

i

-

.

EXECUTIVE SLM4ARY

V. C. Summer Nuclear Station

NRC Inspection Report No. 50-395/97 03

This integrated inspection included aspects of licensee operations,

maintenance, engineering, and plant support. The report covers a 6 week

period of resident inspection; in addition, it includes the results of an

announced inspection by a regional inspector and a project engineer.

Doerations

e The licensee took conservative actions to mitigate any potential reactor

)ower transient during corrective maintenance on a Moisture Separator

Reheater pressure transmitter (Section 01.1).

. A manual reactor trip was initiated following a loss of electro-

hydraulic control system fluid. All safety related components

functioned as ex

with secondary,non pected.

safetySeveral

relatedproblems wereThe

components. identified

licenseeassociated

took

appropriate actions to correct these problems. Operator performance

during these events was acceptable (Section 01.2).

• All safety systems functioned as designed following a turbine trip and

reactor trip. The inspectors concluded that during these events the

plant had operated safely. The response by operators was not based on a

complete awareness of the plant's response to a high high Steam

Generator (SG) level, P-14 actuation. A violation was identified for a

failure to establish procedures appropriate to the circumstances. The

feedwater system operating procedure and the general operating procedure

in use did not provide adequate guidance to ensure that operators could

maintain control of SG levels. The turbine trip abnormal operating

procedure did not provide adequate operating instructions for response

to a turbine trip on high high SG level (Section 01.3).

. Start ups on April 25 and 28 were performed safely, with good control

and communication between the operating staff and reactor engineering.

Reactivity additions were carefully controlled and monitored. On both

start ups critical rod position was within the estimated critical rod

position calculated by reactor engineering (Section 01.4).

• Pressure transients in the Deaerator (DA) had occurred due to the

introduction of cool condensate water into a hot DA. The inspectors

identified an Inspector Followup Item (IFI) to review the cause and

corrective action for these pressure transients (Section 02.2).

• A repeat violation was identified concerning the failure to follow the

applicable procedure to raise the aressure in the reactor building. The

operator opened two containment ex1aust valves rather than the two

containment supply valves called for in the procedure (Section 04.1).

. Lower Auxiliary Building Operator logs were taken in accordance with

Operations administrative procedures (Section 04.2).

l

!

i

-]

.

.

2

.. The Plant Safety Review Committee (PSRC) monthly meeting met Technical

Specification (TS) quorum requirements and focused on safety while

reviewing agenda items (Section 07.1).

At the PSRC meetings prior to plant restart, issues were adequately

documented, discussed and resolved such that there were no open safety

issues affecting a safe plant restart. Plant management ensured that-

all issues affecting plant safety were resolved before plant startup.

The post trip reviews performed by the Independent Safety Engineering

. Group made a contribution to the plant restart effort and provided

useful insights to the events (Section 07.2).

Maintenance

e Maintenance activities were generally conducted in an appropriate and

professional manner. Adequate actions were taken to identify and repair

plant equipment as required (Section M1.1).

• A weakness was identified in the licensee's program for lifting loads in

the yard. The licensee demonstrated poor work practices and non-

conservative decision making on the part of the responsible supervisor

when a Service Water (SW) pump motor was lifted over the top of the

safety related SW pump building with no engineering analysis or

evaluation performed to determine the consequences of a dropped load

onto safety related structures or components (Section M1.2).

. Surveillance activities were conducted satisfactorily and in accordance

with applicable procedures (Section M2.1).

A Non cited Violation (NCV) was identified for the failure to document

and report a deficiency for a Condensate Storage Tank (CST) nitrogen

injection valve surveillance test which was perforved nine times over a

two and a half year aeriod. The test procedure directed the test

performer to open a autterfly valve which could not be fully opened due

to an interference (Section M2.2).

Enoineerina

. The plant responded as designed when the high high SG level caused only

one feedwater isolation valve to close on April 26 (Section E1.1),

a The licensee had made a proactive decision by declaring the A SW pump

motor inoperable based on the similar design of all three motors and on

the similar failures of the B and C motors (Section E1.2).

. The licensee implemented actions to minimize potential damage to safety-

related equipment during the Industrial Cooling Tower replacement

(Section E1.3).

• An Unresolved Item (URI) was identified concerning the cause of an as-

found, out of-specification condition on some Emergency Feedwater (EFW)

system flow control valves and the consequences of higher than expected

. . _ . . . _ ._ . . _ _ _ . _ _ . _ _

. . _ _

_ _ _ _ _ . _ . _ . _ _ . _ _ . . _ _ _ . _ _ _ _ . _ ,

i

.

.

!

l

1

l 3 l

EFW flow differentials. The as left condition of the EFW system was

acceptable (Section E2.1). -

. As part of their Final Safety Analysis Report (FSAR) Review Project, the  ;

licensee has established a method for prioritizing and tracking '

identified FSAR discrepancies from plant operating practices and design i

docunents (Section E7.1). ,

Plant Support

>

e The licensee's program for transportation of radioactive materials had  !

been effectively implemented pursuant to Department of Transportation

and NRC regulations (Section R1.1).  ;

1

. An URI was identified concerning the failure to meet the requirements of i

10 CFR 70.24, criticality accident requirements (Section R2.1). '

. Appropriate compensatory measures were implemented while a modification l

to the protected area fence was in progress (Section S2.1).  ;

!

!

,

!  !

!

!

l

;

h

!

I

i

>

l

l

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

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

.

.

I

Report Details

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On April 17 power

was reduced to 90 percent to support maintenance on a Moisture Separator  ;

Reheater pressure transmitter. Power was returned to 100 percent later on '

April 17. At 4:54 p.m. on April 22 the unit was manually tripped from 100

percent power due to an Electro-Hydraulic Control (EHC) system fluid leak on

the main turbine number one Combined Intercept Valve (CIV) shutdown servo.

The unit remained in Hot Standby (Mode 3) until April 25. On April 25 at 1:45 '

p.m., the licensee commenced a reactor start-up. The reactor was taken

critical at 2:48 p.m. and entered Power Operation (Mode 1) at 6:08 p.m. on

April 25. On April 25 at 9:04 p.m., the licensee commenced a load decrease

from 25 percent reactor power due to another EHC leak on the main turbine

number one CIV shutdown servo. At 9:14 p.m., the turbine was tripped and

reactor power was stabilized at seven percent. On April 26 at 4:20 a.m.,

after repairing the EHC leak, the licensee commenced raising reactor power.

On April 26 at 8:43 p.m., the main turbine tripped on high high SG level from

43 percent reactor power. Four minutes later at 8:47 3.m., the reactor

tripped from six percent power on low low SG level. T1e unit remained in Mode

3 until April 28. On April 28 at 4:40 a.m., the licensee commenced a reactor

start up. The reactor was taken critical at 5:28 a.m. and entered Power

Operation (Mode 1) at 10:15 p.m. on April 28. On May 1 at 6:45 a.m., reactor

power reached 100 percent. The plant remained at full power through the end

of the inspection period.

I. Operations

Conduct of Operations

'

01

01.1 General Comments (71707. 40500) 4

Using Inspection Procedure 71707, the inspectors conducted frequent

reviews of ongoing plant operations. In general, the conduct of

operations was professional and safety-conscious: specific events and

noteworthy observations are detailed in the sections below.

On April 17, licensee took conservative actions to mitigate any

potential reactor power transient during corrective maintenance on a

Moisture Separator Reheater pressure transmitter. The power reduction

to 90 percent and return to full power was performed in accordance with

a standing order and normal operating procedures.

01.2 Manual Reactor Trio Due to Hydraulic Oil Leak

a. Inspection Scope (71707)

The inspectors reviewed the licensee's actions and the plant response

following a manual reactor trip which was initiated because of an EHC

system leak.

,

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

'

. .

2  ;

b. Observations and Findinas

!

On April 22, at 4:54 p.m., control room operators initiated a manual reactor trip from approximately 100 percent power. A main control board

annunciator alarmed indicating an EHC reservoir hi/lo level condition.

Operators were dispatched to investigate the reservoir level and to I

evaluate an EHC system leak on the main turbine number one CIV which was

identified earlier in the week. Local indication of the EHC reservoir

was pegged low and it was reported that the leak on the CIV was much

larger than previously identified. The Shift Supervisor, in ,

consultation with the Associate Operations Manager, ordered a manual '

reactor trip. The resulting turbine trip caused the CIV to close which

isolated the EHC system leak.

The EHC fluid that leaked from the system was contained in the turbine

building sump near the base of the main condenser. The licensee roped

off the area and cleaned up the EHC flu 1d using appropriate personnel

protection and fire prevention measures. No personnel were injured

during this event.

Safety related components functioned as expected on the reactor trip.

All control rods inserted fully. A review of the sequence of events

recorder data revealed that the rod drop times were within the TS

requirements. S3ecifically, the TS requires that all rods must fully

insert in less t1an or equal to 2.7 seconds. For this trip, all rods

fully inserted in 2.539 seconds.

Following the trip, a low low level condition in the A SG caused an

automatic start of the A and B motor driven EFW pumps and subsequent l

feeding of all three SGs. The SG levels were restored to the proper

level. A concern was identified by the licensee involving a larger than

expected EFW differential flow to each of the SGs immediately following

.

the EFW pump start. This concern is discussed in detail in Section E2.1

l of this report.

On the secondary side, several problems were identified following the

trip. These problems, along with the resolutions are discussed below:

. Two of the three Feedwater Regulating Valves (FRVs) (FV-488 for-

the B SG, and FV 498 for the C SG) did not indicate closed on the

main control board as expected. The significance of this was

minimal since all three feedwater isolation valves closed to

prevent overfeeding the SGs.

l The post-trip investigation revealed that FV 488 fully closed as

expected following the reactor trip. The closed limit switch on

'

the valve required adjustment to provide the proper indication on

the main control board. The licensee 3erformed a diagnostic test

,

on FV-498. This test indicated that t1e valve was not operating

as smoothly as expected and that an increase in operating friction

,

had occurred since the last time this test was performed. The

_

,

-

.

l

l

, \

valve was cleaned and lubricated to improve the operation and

placed back in service. l

.

. The B and C Main Feedwater Pumps (MFPs) failed to trip on the

first attempt from the main control board. The pumps tripped on

.the second attempt. All three MFPs were tri) ped in accordance

with Emergency Operating Procedure (E0P), E0)-1.1, " Reactor Trip

Recovery," Revision 7. Step 4(c).

Post trip testing did not indicate any problem with the trip

circuit. The licensee determined that the most probable cause of

this problem was that the operator did not hold the trip switch in

the trip position long enough. A procedure revision to System

Operating Procedure (SOP), S0P-210, "Feedwater System," Revision ,

13 was being developed to instruct the operators to hold the trip l

-

switches until the trip light illuminates.

. The speed changer for the B MFP did not run to minimum speed

. following the pump trip.

The licensee determined that the motor associated with this speed

i changer had an open winding. The motor was replaced and tested

, satisfactory,

i

. Non return check valve (XVC 2014B) from the 2B FW heater to the

Moisture Separator Reheater did not indicate closed on the main

control board. This valve closes on a turbine trip to isolate the

main turbine from the energy contained in the feedwater heater.

The post trip investigation determined that a solenoid

_ malfunctioned on the check valve booster. The main control board

indication comes off the booster which did not function properly.

j However, the check valve disk did go closed as expected following

the trip.

i All of the problems noted were on the secondary, non safety related

equi) ment of the plant. The licensee attributed some of these problems

to t1e long operating run (334 days) the plant experienced prior to the

trip. Much of the equipment which did not function properly following

the trip had not been called on to operate since the last refueling

L

outage in May 1996.

The licensee determined that the cause of the EHC system leak, which

necessitated the manual reactor trip, was a ruptured 0-ring on the shut

down servo on the number one CIV. The servo assembly and the four

associated 0-rings were replaced. The ruptured 0 ring was being

examined to determine the cause of the failure.

At 9:04 p.m. on April 25, with the )lant at 25 percent power, operators

commenced a load decrease when anotler EHC leak was identified. The

magnitude of this leak was less than the previous leak and was such that

reactor power was reduced in a controlled manner to about seven percent

-1

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

,

'

i

!

I

4

and the main turbine taken off-line. The source of the leak was the ,

same number one CIV but from a smaller diameter 0 ring in the shut down

servo. The leak was repaired and on April 26 at 4:20 a.m., the licensee  !

, commenced raising reactor power.  ;

'

c. Conclusions

. A manual reactor trip was initiated following a loss of EHC system

fluid. All safety related components functioned as expected. Several

problems were identified with secondary, non safety related components. l

The licensee took appropriate actions to correct these problems. t

Operator performance during these events was acceptable.

2

01.3 Iurbine Trio and Automatic Reactor Trio j

a. Inspection Scope (71707) l

l

The inspectors reviewed the licensee's actions and the plant response  !

following a turbine trip and an automatic reactor trip on April 26. '

4 b. Observations and Findinas

i On April 26 at 4:00 p.m., the plant initiated a reactor power increase

from 30 to 50 3ercent at approximately three percent per hour. At l

8:40 p.m., wit 1 reactor power at 42 percent, while areparing to start a

second MFP and a third FW booster pump, operators o> served SG water

levels trending downward. In response to the lowering SG levels,

operators manually raised demand on the MFP master controller on the

3

control board to increase FW flow to the SGs. The adjustments to the  ;

controller caused SG levels to rise quickly. At 70 percent level in the

'

-

SGs, operators observed FRV automatic control to be responding slowly to ,

i

'

control SG levels and took manual control of the FRVs to reduce flow to i

the SGs. At 8:43 p.m., a high high SG level annunciator alarm (79 i

percent SG level) P 14 was received on the C SG. This caused a main

turbine trip, a MFP trip, a start of the motor driven EFW aumps, and a  !

closure signal to the FW Isolation Valves (FWIV) and the F1Vs.

0)erators rapidly lowered reactor power to about seven percent. Only

tie A train FWIV closed on the P 14 signal. This FWIV response was l

questioned. An investigation found the P 14 circuitry responded as  ;

designed (see Section E1.1).

Operators promptly restarted a MFP in an attempt to feed the SGs and

restore levels. At 8:47 p.m., before SG levels could be restored, the

reactor tripped from about seven percent reactor power on low low SG

water level in the A SG (27 percent). With the A FWIV closed and the A

SG being supplied by only EFW flow, level in the A SG could not be

restored before reaching the low-low level setpoint. On the reactor

trip all safety systems functioned as designed.

The investigation of the high high SG level turbine trip showed that

operators had lost control of SG 1evels. The General Operating

Procedure, G0P 4, " Power Operation (Mode 1)," Revision ll, and S0P 210,

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

-

.

j

h

!

L 5

!

i

l "Feedwater System," Revision 13, require establishing a differential

'

l

pressure (dp) between the FW and steam header pressures. The dp is -

established according to a program level given in S0P 210 in order to

! maintain control of FW flow and control of SG levels. The inspectors * ,

l

!

review of dp data subsequent to the turbine trip and reactor trip showed  :

that as power approached 40 percent, FW and steam header dp had trended .

downward to below the program level. At 40 percent power the program dp i

is 130 psid. At 8

40 p.m., according to plant computer data, dp was 60

l psid prior to the adjustment of the FW pump master speed controller by

i the operator. Plant operators, however, stated that they were cognizant  ;

of the program dp in SOP-210 and that their Main Control Board (MCB) l

[

-

instrumentation showed it was being maintained correctly. To compensate  !

for the actual dp and the increasing demand for FW flow the FRVs opened ,

beyond their normal operating position. This reduced the capability of i

the FRVs to effectively control flow to the SGs. - With the reduced flow  !

control capability of the FRVs the adjustment to the FW master

controller to raise lowering SG 1evels caused a significant increase in

FW flowrate and a quick rise in SG levels. The FRVs automatic control

responded slowly to the rapidly rising SG levels. At about 70 percent-

SG level when operators took manual control of the FRVs they were unable

to control flow before the C SG reached the high high SG 1evel setpoint

(P 14) which caused the turbine trip.

Operators interviewed after the event believed they were maintaining the

correct dp between the FW and steam headers and stated they had been

, checking dp on their MCB instrumentation. This is accomplished by

reading the aressure from the FW pump discharge header pressure

instrument ()I-508) and steam header pressure instrument (PI-464C) and

determining the difference to obtain dp. The licensee performed a

calibration check of the HCB instrumentation used to determine dp and

found the instrumentation to be in calibration. The instrumentation,

however, has a 0 to 1300 psi scale with an allowable two percent margin

of error.

As a result, the dp maintained between FW header pressure and steam

header pressure was not adequate to maintain control of SG levels. This

resulted in a loss of SG level control and a high high SG level turbine .

trip from 42 percent power. The inspectors concluded that procedures,  !

'

S0P-210 and G0'P 4 were not adequate to ensure that operators could

maintain adequate control of SG levels. Operators also did not l

recognize the potential loss of SG level control associated with the

FRVs being close to full open, This failure to establish procedures to

accurately control FW dp and maintain SG levels'is identified as a

Violation, 50 395/97003 01.

!

Four minutes after the turbine trip at 8:47 p.m., an automatic reactor

i- trip occurred from six percent reactor aower on A SG low low level.

,

Following the turbine trip the Control Room Supervisor directed <

l operators to lower reactor power to seven percent. Based on operator  ;

,

feedback, the operators believed that FW flow to the SGs could be '

. reestablished promptly to restore SG levels. Lowering reactor power  !

l further to one to three percent for EFW to provide adequate SG level '

l

-_

. ._. _ _ . _ . _ _ _ _ _ . _ _ _ . _ _ _ _ . _ . . _ ,

,

)

,'

'

6

control did not appear to be a priority. Operators failed to recognize

all the component actuations that should be expected on a high high SG

level actuation and did not observe that the A FWIV had closed. When FW

flow was restarted immediately prior to the reactor trip only the B and l

C SGs were receiving FW. All safety systems functioned as designed on i

'

the reactor trip.

j The inspectors concluded that Abnormal Operating Procedure, A0P 214.1,

" Turbine Trip," Revision 2, did not provide adequate operating

instructions for a turbine trip from high high SG level. The inspectors

'

found that o wrators were unaware that they had received a FW isolation

signal and tlat owrators were not familiar with the expected plant

response to a SG ligh high level actuation. This failure to establish

procedures to respond to a high high SG level and resulting turbine trip i

is identified as a second example of Violation 50-395/97003-01. l

-

\

c. Conclusion

All safety systems functioned as designed following the turbine trip and

reactor trip. The' inspectors concluded that during these events the 1

3 plant had operated safely. The response by operators was not based on a

complete awareness of the plant's response to a high high SG level P-14

actuation. The inspectors also concluded that the FW system operating

procedure and the general operating procedure in use did not provide

adequate guidance to ensure that operators could maintain control of SG

1evels. The inspectors concluded that the turbine trip abnormal

operating procedure did not provide adequate operating instructions for

response to the turbine trip on the high high SG level.

01.4 Plant Restarts Following Plant Trips

a. Inspection Scope (71707)

i

The inspectors observed reactor start ups on April 25 and April 28  !

following the plant trips. i

b. Observations and Findinas  !

On April 25 at 1:50 p.m., operators commenced a reactor start up with

rods following the manual reactor trip on April 22. The reactor was

taken critical at 2:48 p.m. on control bank D.

1

On April 28 at 4:41 a.m., operators commenced a second reactor start-up

with rods following the automatic reactor trip on April 26. The reactor .

was taken critical at 5:28 a.m. on control bank D. The control bank D  !

critical. position was within the tolerance allowed by the estimated

critical rod position.

The inspectors observed both start-ups and found that they were

performed in accordance with GOP 3, " Reactor Startup From Hot Standby To

Startup (Mode 3 to Mode 2)," Revision 10. The ins actors noted that  ;

shortly before the actual reactor start ups, the slift crew performing  :

,

i

.

.  :

7

each start up had practiced the evolution in the simulator. Prior to 1

commencing each start-up, a thorough control room pre job briefing was '

conducted covering many aspects of the start-up. The start-ups were i

deliberate, carefully controlled, and performed with clear i

communications. During both start-ups, the reactor operator and Control  !

Room Supervisor were focused on reactor controls and closely monitored l

core response during reactivity additions and the approach to

criticality. Rod withdrawal and core response were coordinated with the

reactor engineer present in the control room. Reactor engineering also

closely monitored both start ups and performed an inverse count rate

ratio plot to monitor the approach to criticality. All systems  ;

functioned as expected during the start up.  ;

l

c. Conclusions

The inspectors concluded that both start-ups were performed safely, with

good control and communication between the operating staff and reactor

, engineering. Reactivity additions were carefully controlled and

monitored. On both start ups. the critical rod position was within the

tolerance of the estimated critical rod position calculated by reactor

engineering.

02 Operational Status of Facilities and Equipment

02.1 Enoineered Safety Feature (ESF) System Walkdown (71707)

The inspectors used Inspection Procedure 71707 to walk down accessible

portions of the A and B diesel generators * air start systems. There

were no concerns identified during these walkdowns.

'

02.2 Feedwater System Waterhammers

a. Inspection Scope (71707)

The inspectors reviewed potential waterhammer/ pressure transient events

associated with the condensate system and DA during the plant restart

from April 25 to April 29. ,

.

b. Observations and Findinas

During the plant restarts following the plant trips, water

hammer / pressure transient events occurred in the condensate system and

the DA. The DA and DA storage tank are the dividing line between the

condensate and FW system and provide deaeration, heating and storage of

condensate prior to use by the FW system. The DA storage tank also

provides sufficient static head to meet FW booster pump net positive

suction head requirements.

Following these pressure transients the inspectors walked down the main

condensate piping on April 29 and did not identify any obvious damage

due to these pressure transients. The inspectors also reviewed the

potential causes of these events with Engineering. The transients

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

. ,

.

-

t

!

!

8

f

l appear to have been caused by the injection of relatively cool .

l condensate water into a hot DA steam space causing flashing of the  !

j

'

condensate, immediate pressure and temperature depression in the DA,  !

bulk boiling and flashing of the DA storage tank water, and high stress

l loads on the DA. At the end of the inspection >eriod Engineering had

not completed their review of these events and lad not proaosed  ;

L corrective actions to prevent similar future transients. Jntil the  !

inspectors review the pending engineering evaluation and proposed l

corrective. actions by operations, this issue is identified as Inspection i

Followup Item. IFI 395/97003 02. l

,

c. Conclusion

l The inspectors concluded that the pressure transients had occurred due

to the introduction of cool condensate water in to a hot DA. The

inspectors identified an IFI to review the cause and corrective action

for these pressure transients.

04 Operator Knowledge and Performance

04.1 Reactor Buildina Ventilation System Operatina Error

.

1

i

.a. Insoection Scope (71707) '

The ins >ectors reviewed the circumstances associated with an operator

error t1at occurred while attempting to raise Reactor Building (RB)

pressure using the RB Ventilation System.

I

b. Observations and Findinas j

s

On April 13. -the control building operator attempted to raise RB l

pressure after receiving a containment low differential pressure alarm. j

This is a relatively routine operation that is to be performed in i

accordance with 50P-114. " Reactor Building Ventilation System," Revision

15 Section III.N. While performing Step 2.2 the operator opened valves l

PVG 6066 and PVG 6067, containment purge exhaust isolation valves l

instead of PVG 6056 and PVG 6057, containment alternate purge supply '

isolation valves. This resulted in a slow decrease in RB pressure

instead of the expected increase. No TS limits were exceeded during ,

this event and the misaligned valves were identified by a second

'

i

operator and the correct valve lineup was established.

'

l

This event was a repeat of an identical error which was documented in

Inspection Report No. 50 395/96013. The earlier event occurred on

,

November 12, 1996, and was one of two examples that was identified as an

L NCV 50 395/96013 01. The licensee's corrective actions for the 1996

l event were documented in Condition Evaluation Report (CER)

'

96 0345. At that time, the individual involved was counselled as to the  !

! proper use of the approved procedure and self checking. Also, all

operations personnel were briefed on the event by the individual to

-

stress the importance of procedural compliance. The inspectors verified

this action by reviewing the training attendance records. The

-

_ _ _

i

l

9

l

inspectors concluded that these corrective actions could have reasonably

prevented the occurrence of the most recent event. The failure to ,

correctly implement procedure SOP 114 is a violation of TS 6.8.1.a. and

is identified as Violation 50-395/97003 03.

On A)ril 15, the inspectors observed an operator increasing the pressure

in tie RB in accordance with S0P-114.Section III.N of SOP 114 which

l provided instructions for the evolution was identified as " Reference

Only, Procedure Segments May Be Performed From Memory. Must Verify Work

Following Each Segment." The evolution was performed without

difficulty. The inspectors observed that the valves involved in the

April 12 improper valve lineup were identified in the procedure exactly

as they were labeled on the control panel. The inspectors concluded

that the arocedure format and content was adequate to successfully

perform t1e evolution. Several potential procedural enhancements were

discussed with the licensee. For example, the inspectors noted that

Steps 1.6 and 1.7 identified gaseous and iodine radiation monitors

RMA0004 and RMA0002 in a manner different than the nomenclature on the

control panel equipment identification label.

c. Conclusions

A repeat violation was identified concerning the failure to follow the

applicable procedure to raise the pressure in the RB. The operator

opened two containment exhaust valves rather than the two containment

supply valves called for in the procedure.

04.2 Lower Auxiliary Buildina 00erator Rounds

a. Inspection Scope (71707)

The inspectors observed the licensee performing lower auxiliary building

operator rounds.

b. Observations and Findinas

On April 14, the inspectors observed the night shift Lower Auxiliary

Building Operator recording his TS logs. The inspectors verified that

tha log was taken in accordance with Operations Administrative Procedure

(OAP), 0AP 106, " Operating Logs " Revision 6. Change A. The log

readings were recorded on a hand held data entry device. The inspectors

verificd that selected values were correctly entered and reviewed the

recorded log with the operator upon completion of his rounds. All data

taken met acceptance criteria and channel checks were performed as

required by TS.

l

c. Conclusions

l Lower Auxiliary Builaing Operator logs were taken in accordance with

'

OAPs.

_ a 4 _a .--s a 6, 4* +4.-R -w & ~-A = = W

.

10

07 Quality Assurance in Operations

07.1 Plant Safety Review Committee (PSRC) Monthly Meetina

a. InsDeCtion SCoDe (71'707)

The inspectors observed the conduct of the monthly PSRC meeting.

b. Observations and Findinas

The PSRC monthly meeting on April 15 met TS quorum requirements and

focused on safety while reviewing agenda items. Focus on safety was

demonstrated by deferring ap3roval of a proposed change to Station

Administrative Procedure (SA)) SAP 123. " Procedure Use And Adherence,"

Revision 1, Change B, until questions concerning the 10 CFR 50.59

process and FSAR revision process were addressed.

c. Conclusions

The PSRC monthly meeting met TS quorum requirements and focused on

safety while reviewing agenda items.

07.2 Observation of PSRC and Independent Safety Enaineerino Group (ISEG)

' Activities

a. Insoection Scope (71707)

The inspectors observed the_ conduct of PSRC meetings on April 25 and

April 27 to discuss plant restart issues and make a decision on plant

restart. The inspectors also observed ISEG involvement in the

evaluation of post trip documentation and their evaluation of the cause

of the reactor trips.

b. Observations and Findinas

Following both reactor trips, PSRC meetings were convened prior to plant

restart to review the resolution of restart issues and determine plant

readiness for restart. The PSRC meetings discussed each restart issue

in detail. The cause and the resolution of the significant issues were

presented to the PSRC by the responsible engineer and then discussed.

The questioning and discussion during the meeting was penetrating and

reflected a desire to reach a safe resolution of the issues.

The inspectors also observed the ISEG involvement in the review of post

trip documentation and data, in the PSRC meetings, and in the resolution

of post trip issues. ISEG made several observations that'provided

useful insights to the events.

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

.

,

i

11

c. Conclusions

.

,

The inspectors concluded that all issues were adequately documented,

discussed and resolved at the PSRC meetings such there were no open i

safety issues affecting a safe plant restart. The inspectors noted that i

plant management ensured all issues affecting plant safety were resolved

before plant startup. The inspectors also concluded that the post trip

.

i

reviews performed by ISEG had made a contribution to the plant restart

effort and provided useful insights to the events.

II. Maintenance i

M1 Conduct of Maintenance

M1.1 k neral Comments

a. Inspection Scope (62707) ,

i

.The inspectors reviewed or observed all or portions of the following )

work activities

• Maintenance Work Recuest (HWR) 9700064, Investigate and repair i

cause of C Service Water'(SW) pump motor tripping. l

l

'

. MWR 9709982, Perform flow scan on feedwater regulating valve

FV 498.

. MWR 9710078. Feedwater pumps main speed setpoint station failure

detection.

b. Observations and Findinas

On April 1 the licensee attempted to place the C SW pump in service on

train A to allow the A SW pump to be tagged out to perform maintenance

on the A SW screen wash isolation valve. Several seconds after the

C SW pump start, the motor tripped on a 50G ground relay. Electrical

maintenance personnel performed a megger test on the motor which

indicated a possible fault to ground and damage to the motor. The

operator present at the motor monitoring the start stated that there was

a smell of burned insulation when the pump start was attempted. The ,

licensee tagged out the motor and shipped it off site to be repaired. '

The inspectors did not identify any concerns with observed maintenance

associated with the SW yump with the exception of a concern identified

during the lifting of tie pump motor. This concern is described in

detail in Section M1.2 of this report.

4

Followirig the manual reactor trip on April 22, it was observed that the

FRV for the C SG (FV-498) did not close fully as expected. The licensee

wrote an HWR to perform a diagnostic test on this valve to determine the

.

.

12

cause of the failure. A slight increase in operating friction was

observed. The valve was cleaned and lubricated and returned to service.

c. Conclusions

Maintenance activities were generally conducted in an appropriate and

professional manner. Adequate actions were taken to identify and repair i

>

plant equipment as required.  !

M1.2 Liftino of C SW Pumo Motor

a. Insocction Scope (62707)

The inspectors observed the removal of the C SW pump motor from the SW ,

pump building to a flat bed trailer for shipment off site for repairs. l

I

b. Observations and Findinos

On April 2, the inspectors observed the licensee remove the C SW pump

motor from the SW pum) building and load it on to a flat bed trailer for

shipment off site to ]e repaired. This required two separate lifts and

two different lifting devices. The first lift was done inside the SW

building using an installed overhead crane to lift the motor from the

motor base to a track mounted skid that carried the motor to the opening i

of the SW pump building. From the SW building opening, an outside crane '

lifted the motor from the skid and lowered it onto a trailer. The motor

weighs approximately 16,000 pounds.

While observing this activity, the inspectors noted that the outside

load path for the motor was over the SW pump building which is a

safety-related structure. Specifically, when the motor was lifted from

the skid on the south side of the SW pump building using the outside

crane, it was swung over the southwest corner of the building and

lowered onto the flat bed trailer which was parked on the west side of

the pump building.

The inspectors reviewed General Maintenance Procedure (GMP), GMP-

100.015. " Miscellaneous Crane Operators," Revision 3. This is a safety-

related procedure which was written as part of the licensee's commitment

to NUREG 0612. " Control of Heavy Loads at Nuclear Power Plants." This

procedure addresses the use of all cranes and hoists used in the yard.

Section 7.4 of this procedure provides the requirements for performing

critical lifts. Paragraph 7.4.1 describes a critical lift as follows:

" Selected items due to their size, configuration or

susceptibility to damage require controls in excess of

those previously identified. These items are to be

determined by the responsible supervisor."

Attachment II of GMP 100.015 " Critical Lift Checklist," is required to

be used for all critical lifts. Part I of this checklist is to be

filled out by the responsible job supervisor with assistance from an

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

'

. .

, i

!

5

13  ;

4

engineer to determine if a safe load path is required and the planned

, route. The licensee did not consider the lift of the C SW pump motor to '

be a critical lift and therefore did not use Attachment II to plan the

path of the lift. For this lift, no engineering analysis was performed l

to determine the consequences of a dropped load to the SW pump building

or to the safety-related components inside the building.

,

The licensee has designated the responsible job supervisor with the

responsibility to determine when and if engineering personnel are to be r

, consulted as to the consequences of a lift in the yard. The inspectors  !

considered this responsibility misalaced since the supervisor may not be

familiar with the construction met 1ods used for safety related'

4

structures and is not in a position to perform an adequate evaluation

for the consequences of a dropped load. The inspectors discussed this i

with plant management. They acknowledged the inspectors' comments. )i

l The inspectors concluded that the lift of the C SW pump motor over the, )

, safety-related SW pump building to be an example of a poor work practice j

i and non conservative decision making. This is identified as a weakness i

'

in the licensee's program for lifting loads in the yard. l

,

c. Conclusions

-

A weakness was identified in the licensee's program for lifting loads in

the yard. The licensee demonstrated poor work practices and non-

, conservative decision making on the part of the responsible supervisor

.

when a SW pump motor was lifted over the top of the safety related SW l

pump building with no engineering analysis or evaluation performed to 1

i determine the consequences of a dropped. load onto safety related

structures or components.

5 M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Surveillance Observation

'

a. Insoection Scope (61726)

':

The inspectors reviewed or observed all or portions of the following

' surveillance tests

. STP 130.003, " Valve Operability Testing (Modes 1, 2 and 3),"

. Revision 4

,

. STP-142.005, " Turbine Trip Actuation Device," Revision 3

. ICP-310.008, " Reset High Flux At Shutdown Alarm," Revision 3

,

• STP 134.001, " Shutdown Margin Verification," Revision 8 I

• STP-102.001 "NI Analog Channel Operational Test," Revision 5

!

.

'

.

14

b. Observations and Findinas

On April 23, the licensee performed STP-130.003, Section 6.5, "Feedwater

System Valve Testing," Step 1. The purpose of this section was to test

the K648 and K649 train A output relays to ensure that they function to

close the main FW bypass valves. Step 6.5.i.2 directs the test

performer to energize the K648 output relay by turning test switch.

S 841, to the right hand position, depress and hold. During the

performance of this step, the relay failed to energize. The licensee

determined that the test switch may not have been operated correctly or

that the test switch was mechanically bound preventing the switch from

making good contact. The test was reperformed twice with satisfactory ,

results following the initial failure. When the circuit is lined up for

normal operation, the test switch is bypassed such that a faulty test

switch would have no effect on the operation of the K648 output relay.

The inspectors did not identify any concerns with the licensee's actions

regarding this test failure.

'

c. Conclusions

Surveillance activities were conducted satisfactorily and in accordance

with applicable procedures.

M2.2 CST Nitroaen In.iection Check Valve Test

a. Inspection Scooe (61726)

j

1

The inspectors reviewed the performance of STP 220.009, " Closure Testing I

of XVC01067 EF, CST Nitrogen Injection Check Valve," Revision 0.

l

.

b. Observations and Findinos

On April 25, licensee test unit personnel attemated to perform

STP 220.009 to demonstrate the full closed capa)ility of the CST

nitrogen injection check valve, XVC01067-EF. Step 6.1.3 directs the

test performer to open XVB01035 EF, CST drain valve. The test performer

could not fully o)en this butterfly valve because of interference which

would not allow t1e valve o>erating handle to rotate through a full

circle. Because of the ina)ility to fully open this valve, the test

performer wrote a test deficiency for this test and declared the test j

unsatisfactory. j

!

This test procedure had been in place since November 1994. A records  !

review revealed that the test had been performed nine times and signed '

off as satisfactory. During these previous tests, the test performers

did not identify the aroblem with XVB01035 EF but instead opened the

valve as far as possi)le given the interference and continued with the

test. i

!

Procedure SAP 134. " Control of Station Surveillance Activities "

Revision 8, Section 5.5.1, describes the responsibilities of the test

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

.

! 15 -

e

performer. Paragraph 5.5.1.A.7 describes one of the test performers

-

responsibilities as follows:

" Documenting and reporting Test Deficiencies, i

i immediately to the Shift Supervisor and Responsible

Supervisor for corrective action."

The test performers for the previous nine tests between November 1994  ;

.

and April 1997 did not identify as a test deficiency the inability to

fully open the CST drain valve as directed by the test procedure.

1

The inspectors reviewed the test methodology and the acceptance criteria i

to determine if the previous tests were satisfactory even though the CST

drain valve could not be fully opened. The inspectors concluded that

the test results were acce) table despite the inability to perform the

test as written since the Jackleakage past the nitrogen injection check

valve being measured was a relatively small amount (less than one gallon  !

per minute (gpm)). This amount of water could be 3assed through the '

partially open butterfly valve and prcub accepta)le test data.

1

. Once the problem was identified, the licensee took appropriate

j. corrective actions. Specifically, the test procedure was revised to

>

instruct the test performer to throttle open XVB01035 EF. Also, test .

>

unit personnel were counseled as to the expected actions to be taken 1

when a test 3rocedure could not be performed as written. The inspectors 4

considered t1ese actions to be adequate.

-

The failure to document and report a long standing test deficiency for

the CST nitrogen injection check valve test is identified as a

. violation. This licensee identified violation is being treated as an

i NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This

is identified as NCV 50-395/97003-04.

.

c. Conclusions ,

An NCV was identified for the failure to document and report a

deficiency for a CST nitrogen injection valve surveillance test which

was performed nine times over a two and a half year period. The te.st

i

procedure directed the test performer to open a butterfly valve which

could not be fully opened due to interference.

III. Enaineerina

El _ Conduct of Engineering

E1.1 Seal-in Function of Hioh Hiah SG Level Turbine Trio (P-14)

a. Inspection Scope (37551)

On the high high SG level actuation on April 26, the FW isolation signal

closed only the A train FWIV. The inspectors reviewed the function of

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

-

. ,

l

!

16 i

the P 14 signal to determine if this had been the correct plant

response.

b. Observations and Findinas

i

A review of the TS Bases following the event found that the automatic i

functions of P-14 are not necessary for ESF system actuation but enhance

the overall reliability of the ESF functions. The licensee's review of

design information found that P 14 does not require a seal in function.

It is required to prevent overfilling the SG and has no specific

requirements if the SG level is below the P 14 setpoint.

The P 14 FW isolation function on April 26 closed only the A train FWIV.

The licensee's review found that if the P-14 signal' actuates and resets

before a FWIV has cleared its full o>en limit switch the FWIV.will

remain open. The licensee also checced the full open limit switches on

the FWIVs to verify no obvious misalignment or switch failure. There

were no problems identified. The licensee is also reviewing from an

operating standpoint if it is wise to not have all FWIVs close on a FW

isolation signal. The inspectors had no further questions. j

c. Conclusions j

The ins)ectors concluded that the plant had responded as designed when

the higdhigh SG level had caused only one FW isolation valve to close. ,

El.2 SW Pumo Motor Failures

a. Inspection Scope (37551)

The inspectors reviewed Engineering's resolution of two SW pump motor

. failures.

,

b. Observations and Findinas l

!

As described in Section M1.1 the C SW pump motor failed on April 1. The l

investigation of the motor failure found that the motor had physical

damage to the stator coils. The motor was sent off site for repair.

Visual inspection at the vendor confirmed that there was physical damage

to three coils off a line connection. This damage had created a carbon

track to the frame of the motor which was detected by a ground fault

relay. The testing at the vendor confirmed that the motor failure was

caused by one or more turn to turn faults in the coils and that

rewinding of the stator was required. Late in 1996, while in a vendor's

repair facility for maintenance, the B SW pump motor had experienced a

similar failure.

Based on the similar failures of the B and C SW pump motors, the

licensee declared the A SW pump motor inoperable on May 2 until it could

be sent off site for rewind of the coils. This licensee's decision was

based on the fact that all three SW pump motors were the same age and

design and have been exposed to the same environmental and operational

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

.

.

( 17 I

'

conditions. It appeared to the licensee that the insulation used on the i '

j . coils had reached the end of its useful life.

c. Conclusions

The inspectors concluded that the licensee had made a )roactive decision

by declaring the A SW pump motor inoperable based on t1e similar design

of all three motors and on the similar failures of the B and C motors.

E1.3 Industrial Coolina Tower Modification

a. Insoection Scope (37551. 71707)

The inspectors reviewed Engineering Information Request (EIR), " Review

of Lifting and Rigging Operations Associated With ECR 50028. Industrial

Cooling Tower Replacement, For Compliance With NUREG 0612 " Revision 1

dated March 26, 1997. The inspectors also attended the pre job brief

prior to the initial crane lift.

b. Observations and Findinas

The inspectors reviewed crane operations associated with the Industrial

Cooling Tower Modification. Although the Industrial Cooling Towers are

not safety related, the towers are located on the safety related

Auxiliary Building roof. Replacement of the towers involved moving  ;

equipment and components via crane onto and off the Auxiliary Building

'

roof and in proximity to other safety related structures and components.

The EIR adequately addressed questions associated with crane operations.

The EIR demonstrated that with restrictions on load height and crane

boom configuration the consequences of a dropped load or a failed crane

boom would not place the facility in an unanalyzed condition.

The inspectors concluded that the licensee had implemented actions to

minimize potential damage to safety related equipment during the

Industrial Cooling Tower replacement. Specifically, safe load paths

were established for crane operations, safety related equipment and

structures were identified to the crane operator and riggers, and

precautions were identified to safely aerform the crane operations. In

addition, the pre job brief prior to t1e initial crane lift adequately

addressed potential safety concerns and precautions to address those

concerns: discussed individual res)onsibilities for operations,

maintenance, engineering, health p1ysics, security, and contract

personnel: and established appropriate communication links.

c. Conclusions

The inspectors concluded that the licensee had implemented actions to

minimize potential damage to safety related equipment during the

Industrial Cooling Tower replacement.

l

l

-.

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

- ,

,

e

!

18 ,

.E2 Engineering Support of Facilities and Equipment  !

E2.1 EFW Flow Balance

,

a. Inspection Scope (37551)

The inspectors reviewed the licensee's actions regarding a larger than

expected differential flow to each of the three SGs following the manual reactor trip on April 22.

b. Observations and Findinas i

Following the reactor trip on April 22, the A and B motor driven EFW

pumps started automatically.due to a low low water level condition in i

the A SG. It was noted on the EFW actuation that there appeared to be a  !

large differential in EFW flows to each SG. Six minutes after the i

reactor was tripped, the approximate EFW flow rate to each of the SGs '

was as follows:

Steam Generator A 380 gpm i

Steam Generator B 302 gpm l

Steam Generator C 263 gpm

This flow rate data was taken when the SG pressures were essentially

equal. These numbers give flow differentials of approximately 78 gpm

between the A and B SGs, 39 gpm between the B and C SGs, and 117 gpm

between the A and C SGs. These differential flow rates were higher than

those observed during prior trips. The maximum differential flow rates

observed during the last three trips were as follows:

August 25, 1989 56.2 gpm

May 21, 1992 45.2 gpm

January 12, 1993 56.9 gpm

The licensee concluded that the change in the maximum differential flow

rates observed during the April 22 trip was as a result of a physical

change in the EFW system.

Post trip testing and inspections determined that the motor driven EFW

pump flow control valve mechanical stops for the A SG (IFV-3531) and the

B SG (IFV 3541) were not within s)ecifications. The vendor drawings for 1

these valves specify that the meclanical stops should be adjusted to '

limit the valve travel to 2-9/16 inches. The as-found valve settings j

were 31/4 inches on the A SG valve and 2 45/64 inches on the B SG i

valve. The licensee wrote Non conformance Notice (NCN) 97-0366 and 97- l

0366A to address this condition. The valve mechanical stops were  ;

adjusted to within specification. Subsequent testing indicated that the '

EFW flow differential was consistent with past test results. The  !

inspectors agreed that the as left condition of the EFW system was j

acceptable for continued plant operation.

l

- , , -

-

- - - - ~ . .> - . ~ . , n

~

. ,

)

'

19 j

i

The licensee initiated a root cause evaluation effort to determine the i

cause of the out of specification valve stop adjustments and the

- consequences of the higher than ex)ected EFW flow differentials.  ;

Pending the inspectors review of t1e results of this evaluation, this {

. will be considered an Unresolved Item (URI) 50-395/97003 05. j

.

c. Conclusions

A URI w6s identified concerning the cause of an as found,

out of specification condition on some EFW system flow control valves

and the consequences of higher than expected EFW flow differentials.

1'

The as-left condition of the EFW system was acceptable.

,

E7 Quality Assurance in Engineering Activities (37551)

E7.1 Review of Vodated Final Safety Analysis Reoort (UFSAR) Commitments

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 compared plant practices, procedures.and/or

parameters to the UFSAR description. While performing the inspections i

discussed in this report, the inspectors reviewed the applicable  !

ortions of the FSAR that related to the areas inspected. No

iscrepancies were identified.

On April 15, licensing and engineering personnel arovided the inspectors )

with an overview of their FSAR Review Program. T1e inspectors verified

that the licensee has established a method for tracking identified FSAR

discrepancies from plant operating 3ractices and design documents.

Discrepancies are assigned one of t1ree priorities. Priority A items

require immediate evaluation and resolution. Review of Emergency Diesel  !

Generator discrepancies identified no priority B and C items that should i

have been classified as priority A.

IV. Plant Suppor_t

R1 Radiological Protection and Chemistry (RP&C) Controls

l

R1.1 General Comments (71750)

The inspectors observed radiological controls during the conduct of I

tours and observation of maintenance activities and found them to be

acceptable.

R1.2 Transoortation of Radioactive Materials

a. Insoection Scope (86750. TI 2515/133)

The inspectors reviewed selected elements of the licensee's program for  ;

transportation of radioactive materials to determine whether the  ;

licensee properly processes, packages, stores, and ships radioactive  ;

.

20 l

materials and whether the changes to the Department of Transportation

(D0T) and NRC regulations, which became effective on April 1,1996, had ,

been implemented. The review included records for training of personnel

on the changes to the regulations, procedures for preparing radioactive

material for shipment, and shipping papers for selected recent ,

shi>ments. Those procedures and records were evaluated for consistency  :

wit 1 the recuirements delineated in 49 CFR Parts 170 - 179 and 10 CFR 71 !

for licensec material transported outside of the confines of the plant.

]

b. Observations and Findinas

The inspectors reviewed the training records for three individuals

authorized to sign shipping papers and determined that training on the

changes to the regulations had been 3rovided during March 1996, i.e.,

prior to the effective date of the c1anges. Refresher training was also

provided during March 1997. The manuals for that training were also

reviewed and found to have specifically addressed the new rules for the

following topics: Low Specific Activity (LSA) and Surface Contaminated

Object (SCO) hazards, definitions, and requirements: placarding,

labeling, and marking of vehicles and packages: use of Systeme

Internationale (SI) units on shipping papers, labels, and emergency i

response instructions after April 1,1997: fissile classification; waste

classification; and shipping papers. The inspectors reviewed the

currently effective Health Physics Procedures (HPPs) 702, 703, 712, 716,

717, and 724, and determined that the instructions therein were

consistent with applicable DOT and NRC requirements for selection of an

acceptable container for various types of materials, fissile and LSA

classifications, vehicle placarding, package marking and labeling, and

contamination and radiation levels. The licensee also used computer l

programs for guidance in preparing radioactive materials for shipment

and for generating shipping papers. Those programs included libraries

of A and A2 values, i.e., radionuclide activity levels used for

1

selection of proper shipping packages. The inspectors verified that the

A 1 and A 2valuer, for 6 selected radionuclides listed in those libraries

were accurate. The licensee's shipment log indiccted that, as of May 1, 1

the licensec had made 23 shipments of radioactive material this year,

the majority of which were limited quantities in excepted packages of

contaminated protective clothing shipped to a laundry and samples

shipped for analysis. The inspectors reviewed the shi) ping papers for 3

recent shipments consisting of: an underwater vacuum slipped as a SCO: a

cask of resin shipped to Chem Nuclear Systems' Consblidation Facility;

and contaminated protective clothing shipped to a laundry. The

information on the shipping papers was found to be consistent with

applicable DOT requirements and the licensee's procedures. ,

On April 30, 1997, the inspectors observed a package of contaminated

protective clothing being loaded onto a truck for shipment. The

inspectors noted that the package and the vehicle were properly

surveyed, the package was pro]erly marked, and the appropriate

information was recorded on tie shipping papers. The inspectors,

accompanied by the licensee, toured interior and exterior storage areas

used for temporary storage of packaged low-level radwaste awaiting

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

.

\ .

l

,

l 21 ,

l .

,

I shipment, radwaste awaiting further processing, or slightly contaminated i

equipment (tools, scaffolding, etc.) held for reuse. The inspectors i

noted that the containers were appropriately labeled. At the  ;

inspectors' request, the licensee performed dose rate surveys of several

' '

of the containers. The observed dose rates were consistent with the

dose rates recorded on the container's labels. .

L

c. Conclusions

l

t

!

'

Based on the above reviews, it was concluded that the licensee had

effectively implemented a program for transportation of radioactive  ;

materials pursuant to DOT and NRC regulations.

l

s

R2 Status of RP&C Facilities and Equipment  :

!

R2.1 Comoliance with 10 CFR 70.24. Criticality Accident Reouirements i

a. Inspection Scope (71750)

,

The inspectors reviewed the licensee's facilities, equipment, and

procedures to ascertain if they complied with the requirements of 10 CFR

70.24, criticality accident requirements. '

!

b. Observations and Findinas l

The portions of 10 CFR 70.24 which are applicable to the V. C. Summer i

station state that a licensee authorized to possess special nuclear J

material in sufficient quantities is required to maintain a monitoring

system in the area where this material is handled, used, or stored. The

monitoring system shall be capable of detecting a criticality that

produces an absorbed dose in soft tissue of 20 rads of combined neutron

and gamma radiation at an unshielded distance of 2 meters from the

reacting material within one minute. Coverage of all areas shall be

provided by two detectors. The detectors must energize clearly audible

alarm signals if accidental criticality occurs.

Also, the licensee must maintain emergency procedures for each of these i

areas to ensure that all personnel withdraw to an area of safety upon  !

the sounding of the alarm. These procedures must include the conduct of j

drills to familiarize personnel with the evacuation plan and designate a i

responsible individual to determine the cause of the alarm. In '

addition, the licensee ,must have radiation survey instruments in

accessible locations for use in an emergency. .

l

The inspectors reviewed NUREG 0717. " Safety Evaluation Report (SER)  !

Related to the Operation of Virgil C. Summer Nuclear Station, Unit 1," i

issued in February 1981. Section 12.3 of this document states:

The applicant has provided area radiation monitors around

the fuel storage areas to meet the requirements of Section

I

70.24 of 10 CFR Part 70 and to be consistent with the

I

22

guidance of Regulatory Guide 8.12 " Criticality Accident

Alarm Systems."

An initial search of licensee records failed to locate documents

submitted to the NRC that supported this statement. As a result, the

inspectors attempted to independently verify that the licensee was in

compliance with the requirements of 10 CFR 70.24. The fuel har.dling

bridge crane radiation monitor (RM G8) is located inside the Fuel

Handling Building and provides a local audible evacuation alarm. The

RM G8 radiation monitor range starts at 0.1 mR/hr. This range is

sensitive enough to detect an inadvertent criticality anywhere in the

Fuel Handling Building which would produce an amount of radiation

described in 10 CFR 70.24. The Fuel Handling Building exhaust radiation

monitor (RM A6) is located immediately outside the Fuel Handling

Building in the Auxiliary Building. The RM A6 radiation monitor is

attached to the ventilation duct associated with the Fuel Handling

Building and would be capable of detecting airborne radiation which

would be produced by activation of particles and gases during a

criticality event. The licensee was unable to provide documentation

that the RM A6 radiation monitor was capable of meeting the sensitivity

requirements of 10 CFR 70.24. The RM A6 radiation monitor energizes an

alarm in the main control room but provided no audible alarm in the Fuel

Handling Building. Thus if a criticality event would occur, the control

room operators would be required to respond to the alarm, evaluate the

condition and then announce evacuation of the Fuel Handling Building.

One purpose of a criticality monitoring system is to allow rapid

personnel evacuation from potentially lethal radiation dose rates.

Since the RM A6 radiation monitor did not provide an alarm inside the 1

Fuel Handling Building, the inspectors concluded that the RM A6 i

radiation monitor did not meet the 10 CFR 70.24 requirement for l

providing a clearly audible alarm signal if an accidental criticality

were to occur. The inspectors verified that portable radiation

monitoring instruments would be available to assess the radiation

hazards during a criticality event.

4

The inspectors discussed with the Manager of Nuclear Licensing and

Operating Experience the conflict between the results of this inspection

and NUREG 0717. The discussion also addressed the unavailability of

information to demonstrate that the RM A6 radiation monitor meets the

sensitivity requirements of 10 CFR 70.24. The inspectors were informed

that the licensee plans to request an exemption from 10 CFR 70.24.

The inspectors reviewed the licensee's procedures regarding radiation

emergencies. Several procedures were in place which direct personnel on

the appro)riate actions to be taken in the event of a radiation monitor

alarm. T1ese procedures included Emergency Plan Procedure (EPP) 012, i

"0nsite Personnel Accountability and Evacuation," Revision 11: HPP 407,

" Controls for Receipt of New Fuel," Revision 3: A0P-123.3, " Potential

Fuel Assembly Damage During Refueling," Revision 1: and Annunciator

Res)onse Procedure (ARP)-019. " Fuel Handling Building Bridge Area RM G8

Hi lad," Revision 0. Also, each employee and contractor on site

receives station orientation training which includes instruction on

i

• l

23

emergency evacuation. Health Physics personnel have been designated to

determine the cause of the alarm and conduct surveys using portable

radiation monitoring instruments which are maintained in an area which

would be accessible in the event of an inadvertent criticality.

The inspectors reviewed the status of drills to familiarize personnel on

the evacuation procedures. On March 7, 1984, a drill was conducted 1

involving RM G8 and RM A6. The scenario involved the evacuation of  !

personnel and was initiated by the. failure of a reactor building purge i

line isolation valve. Actions taken during this drill were similar to

those required for an inadvertent criticality event. The inspectors ,

considered this drill to meet the requirements of 10 CFR 70.24. A  !

recent drill was conducted on March 12, 1997, after the licensee became i

aware that the NRC was conducting inspections for compliance with 10 CFR- l

70.24 at other nuclear power plants. The inspectors considered the time I

between these two drills (approximately 13 years) to be excessive. The  ;

requirements of 10 CFR 70.24 state that the licensee shall maintain l

emergency procedures to ensure that personnel withdraw to an area of

safety upon the sounding of the alarm and to familiarize personnel with i

the evacuation plan. The inspectors concluded that the emergency  !

procedures and personnel familiarization with the evacuation plan were ,

not being maintained because of the excessive time since appropriate  !

drills were conducted. '

The installed radia*.>on monitoring system and maintenance of emergency

procedures (drills) o not meet the requirements of 10 CFR 70.24.

Issues involving compliance with the requiremer.ts of 10 CFR 70.24 are

currently being reviewed by the NRC. Until this review is completed, ,

this issue is identified as URI 50-395/97003 06. l

<

c. Conclusions

An URI was identified concerning the failure to meet the requirements of  ;

10 CFR 70.24, criticality accident requirements.

S2 Status of Security Facilities and Equipment

l

S2.1 Security Walkdown

On April 30, the inspectors walked down modifications being made to the

protected area fencing with the plant Security Manager. The inspectors

verified that appropriate compensatory measures were implemented while

the modification was in progress. The inspectors also toured the  ;

Central Alarm Station and toured other plant areas to review security i

measures. The inspectors identified no concerns.

!

,

_ _ _ __ _ _ __ _ . _ _ _ _ _ _ _ , _ __ _.._ . .

24

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors ) resented the inspection results to members of licensee

management at t1e conclusion of the inspection on May 12, May 20, and

May 30, 1997. 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.

PARTIAL LIST OF PERSONS CONTACTED

Licensee

F. Bacon, Manager, Chemistry Services

L. Blue, Manager Health Physics and Radwaste

S. Byrne, General Manager, Nuclear Plant Operations

R. Clary, Manager. Quality Systems

M. Fowlkes, Manager, Operations 4

S. Furstenberg, Manager, Maintenance Services i

D. Lavigne General Manager, Nuclear Support Services i

G. Moffatt, Manager, Design Engineering

K. Nettles, General Manager, Strategic Planning and Development

H. O'Quinn, Manager, Nuclear Protection Services l

A. Rice, Manager, Nuclear Licensing and Operating Experience

G. Taylor, Vice President, Nuclear Operations

R. Waselus, Manager, Systems and Component Engineering

R. White, Nuclear Coordinator, South Carolina Public Service Authority

B. Williams, General Manager, Engineering Services

G. Williams, Associate Manager, Operations

INSPECTION PROCEDURES USED

l

'

IP 37551: Onsite Engineering

IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and

Preventing Problems ,

IP 61726: Surveillance Observations  !

IP 62707: Maintenance Observations  ;

IP 71707: Plant Operations  !

IP 71750: Plant Support Activities

IP 84750: Radioactive Waste Treatment, and Effluent and Environmental

Monitoring i

TI 2515/133: Implementation of Revised 49 CFR Parts 100-179 and 10 CFR Part 71

!

j

I

I

_ . _

-

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

. .

5

25

ITEMS OPENED AND CLOSED

Opened

50 395/97003 01 VIO failure to establish procedures appropriate to the

4

circumstances (Section 01.3).

! 50 395/97003 02 IFI licensee corrective action to prevent deaerator

.

pressure transients (Section 02.2).

'

50 395/97003 03 VIO failure to follow procedure to raise RB pressure

(Section 04.1).

4

50 396/97003-04 NCV failure to follow procedure to document and report a

long standing test deficiency (Sect. ion M2.2).

50 395/97003 05 URI evaluation of high emergency feedwater system

i differential flow rates (Section E2.1).

! ~50 395/97003-06 URI failure to meet the requirements of 10 CFR 70.24,

7

criticality accident requirements (Section R2.1)

Closed

50 395/97003 04 NCV failure to follow procedure to document and report a

long standing test deficiency (Section M2.2).

)