ML20128H695

Insp Repts 50-369/96-07 & 50-370/96-07 on 960728-0907. Violations Noted.Major Areas Inspected:Licensee Operations, Engineering Maint & Plant Support

ML20128H695
Person / Time
Site:	Mcguire, McGuire
Issue date:	10/02/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20128H654	List: ML20128H648 ML20128H663 ML20128H686 ML20128H695
References
50-369-96-07, 50-369-96-7, 50-370-96-07, 50-370-96-7, NUDOCS 9610100036
Download: ML20128H695 (22)

See also: IR 05000369/1996007

Text

. . . . . . _ __ _ _ . _ _ _ _ _ _ _ _ _ _ . _ . _ _

E

'

. .

,

l .

U.S'. NUCLEAR REGULATORY COMMISSION

-

REGION II

.

Docket Nos: 50-369. 50-370

License Nos: NPF-9. NPF-17

4

Report No: 50-369/96-07, 50-370/96-07

i

Licensee: Duke Power Company

i

Facility: McGuire Generating Station. Units 1 & 2

I Location: 12700 Hagers Ferry Rd.

,

Huntersville NC 28078

,

Dates: July 28 - September 7. 1996

.

! Inspectors: S. Shaeffer. Senior Resident Inspector

4

G. Maxwell. Senior Resident Inspector

>

M. Sykes Resident Inspector

i G. Harris. Resident Inspector

! S. Rudisail. Project Engineer

i

j Approved by: L. Wert. Acting Chief

4 Projects Branch 1

,

Division of Reactor Projects

1

J

'

f

i

$

Enclosure 3

1

9610100036 961002

PDR ADOCK 05000369

G PDR ,

)

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

',

'

1

.

l

EXECUTIVE SUMMARY

' ' '~~'

McGuire Generating Station. Units 1 & 2

NRC Inspection Report 50-369/96-07. 50-370/96-07

This integrated inspection included aspects of licensee operations, engineer-

l ing, maintenance, and plant support. The report covers a 6-week period of

resident inspection.

1

Ooerations 1

. Failure to perform TS required surveillance involving onsite Emergency

AC Power was identified as Violation 50-369. 370/96-07-01

(paragraph 04.1).

• A failure to monitor waste gas tank activity limits was identified as a

non-cited Violation. (paragraph 04.1)

l * Operator response to the initial indications of a Unit 1 steam generator

,

tube leak were considered good (paragraph 04.2).

l

l . Performance during the recent Emergency Drill identified that Operations

l was not able to activate the Standby Shutdown Facility within 10 minutes

l to preclude potential reactor coolant pump seal damage during a loss of

'

all AC event. Immediate corrective actions were taken which modified

operating procedures to immediately implement SSF activation procedures

during a loss of all AC event. IFI 50-369.370/96-04-05 will remain open

for additional review (paragraph Pl.1).

Maintenance

. The licensee identified a failed Unit 2 Train B Bypass Reactor Trip

Breaker auxiliary switch connection during Solid State Protection System

testing. The inspectors concluded that the replacement of the breaker

component was performed in an adequate manner. (paragraph M2.1)

l . Potential improper electrical isolation for Post Accident Monitoring

instrumentation was identified as URI 50-369.370/96-07-03 (paragraph

'

M7.1)

Enoineerina

. An inadequate design of containment airlock door testing components was

identified as a non-cited Violation. (paragraph E8.1)

. Deviation 50- 369. 370/96-07-04 was identified for failing to meet an

NRC commitment specified in the licensee's response to Generic Letter 88-03. Steam Binding of Auxiliary Feedwater Pumps. Also, an additional

example of URI 50-369.370/96-04-02. FSAR Inconsistencies, was identified

related to the licensee's operation of the Auxiliary Feedwater system.

(paragraph E7.1)

Enclosure 3

. -

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

!

i

i

l .

i

! Executive Summary 2

i

'

e An inadequate 10 CFR 50.59 evaluation for the Unit 1 and Unit 2 i

auxiliary feedwater system was identified as Violation 50-369. 370/96- .

'

07-05. The licensee failed to fully evaluate the effects of system i

voiding and also did not adequately address system temperatures

exceeding piping design limits.( paragraph E7.1)  ;

e Failure to take effective corrective action for an EDG fuel line failure i

was identified as a violation of 10 CFR50. Appendix B. Criterion XVI. ,

This was identified as Violation 50-369. 370/96-07-07. (paragraph E8.2) i

e A weakness was identified for not re-evaluating system operability when

the root cause was established (paragraph 03), l

. The inspectors identified that the timeliness of actions to correct

previously identified problems involving fuse replacement needed to be

re-evaluated based on recent failures which resulted in inoperable ECCS

sub-systems. (paragraph 02.1)

Plant Sucoort

e A review of the August 5. Emergency Preparedness Table Top Exercise

Drill concluded that the scenario was realistic and the overall

emergency preparedness training was conducted in a professional manner.

(paragraph Pl.1)

1

Enclosure 3

.

Reoort Details

Summary of Plant Status

Unit 1 operated at 100 percent power throughout the ins)ection period. On l

August 30. the licensee identified a steam generator tu]e leak in the 1 B i

steam generator. At the close of the inspection period, the leak rate

remained stable at approximately 6 gpd.

Unit 2 operated at 100 percent power throughout the period.

1

'

I. Operations

01 Conduct of Operations

01.1 Gene al Comments (71707)

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.

02 Operational Status of Facilities and Equipment (71707)

02.1 Fuse Failure in RN Modulatina Valve Reset Circuitry

a. Insoection Scooe

On July 17 while conducting routine control board surveillance the

control room operators discovered that an indicating light in the RN

modulating valve circuitry was 't illuminated. Further investigation

by the licensee revealed that a fuse had blown preventing a single train

of safety-related control valves in the service water, residual heat i

removal, component cooling water, and control room ventilation systems

from moving to their safe position during accident conditions. The

position of the control valves are controlled by non-safety controllers i

'

and non-safety instrumentation.

b. Observation and Findinas

The blown fuse was determined to be an FNQ type fuse. These fuses had

earlier been determined to be suspectable to failure due to a known

design flaw. The licensee had scheduled these fuses to be replaced

with FLQ type fuses under a station modification in 1997. The failure

of the fuse could significantly complicate the mitigation and recovery

from an accident if the fuse were to fail with the other safety train

components not available.

The licensee replaced the affected fuse and modified surveillance

requirements such that control room operators would monitor all ESF

Enclosure 3

1

.

.

.

2

modulating valve reset indications to ensure associated circuitry was

functioning properly. The licensee also prepared a training package to

inform operators of the effects of modulating valve circuitry power

failures. The inspector noted that the licensees immediate corrective

action did not include replacing similar fuses in the remaining RN l

modulating valve circuits. The inspector discussed this concern with '

Engineering management. By the end of the inspection period, the

l'censee indicated that a re-evaluation of the FNQ fuse replacement

schedule would be performed to eliminate other potential fuse failures '

that significantly impact plant safety.

c. Conclusions

The inspectors concluded that the timeliness of corrective actions

involving fuse replacements to correct previously identified problems

needed to be re-evaluated based on recent failures which resulted in

inoperable ECCS sub-systems.

03 Operations Procedures and Documentation (71707)

During the inspection period, the inspector questioned the licensee

regarding the process for re-evaluating operability of degraded systems

and/or components after root cause determinations have been made.

Specifically, the inspector noted that a documented re-evaluation of

operability was not performed when a root cause for a EDG fuel line

failure was finally determined (subsequently discussed in paragraph

(E8.2). The ins)ector concluded that the licensee's process was weak,

such that, a metlod was not in place for ensuring that re-evaluations of

all operability aspects were made after the root causes were determined. ,

'

The inspectors discussed this example with the licensee. PIP 0-M-2156

was initiated to review the inspectors concern for potential process

improvements to ensure operability assessments are performed when

necessary.

04 Operator Knowledge and Performance (71707)

04.1 Failure to Perform Technical Soecification Action Reauirements

a. -Insoection Scooe (93702)

During the inspection period, the licensee failed to perform the

requirements for Technical Specifications surveillance test within the

specified time interval. These cases invMyed surveillance tests on an

EDG and a waste gas decay tank.

b. Observations and Findinas  :

On July 17. 1996, the licensee declared the 1B RN train inoperable due

to a blown fuse in the modulating valve circuitry, which resulted the IB

diesel being declared inoperable (also discussed in paragraph 02.1). TS

Enclosure 3

,

I

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

T

I

! .

i 3

3 3.8.1.1 requires that if a diesel is declared inoperable. the opposite

$

train emergency diesel generator be tested per TS 4.8.1.1.2a(4) and )

4.8.1.1.2a(5) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The Unit 1 Train B emergency diesel  !

generator was declared inoperable when a fuse failed in modulating valve i

circuitry that affected several safety-related systems including the

'

t

nuclear service water system. The opposite train diesel was not run

'

j within the required time period as required by TS. However, a

j subsequent review by the licensee revealed that the nuclear service

3 water system was operable but in a degraded condition. The inspector

noted that this determination did not take place until after the

surveillance period had expired for the test to have been performed on

the opposite train emergency diesel generator.

On August 6. 1995. RP 3ersonnel discr"', ed that a TS surveillance was

not performed within t1e required time period. Technical S>ecifications

surveillance 4.11.2.6 requires that the waste gas decay tants be

monitored once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to ensure proper curie content. The

activity limit of 49.000 curies is verified by the radiation protection

technicians measuring dose rates at designated locations outside the

waste gas decay tank room. RP technicians subsequently performed the

surveillance and determined that the curie content of the tank did not

exceed the Technical Specification requirements. The failure to perform

the required monitoring of TS 4.11.2.6 is a violation. This licensee ,

identified and correcte'i violation is being treated as a Non-cited i

Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy i

(50-369.370/96-07-02. Failure to Monitor Waste Gas Tank).

c. Conclusion

The failure to conduct TS surveillance requirements within the specified

time interval is a Violation. The Violation will be identified as

50/369.370 96-07-01. Failure to Perform Surveillance Testing within

Specified Time Interval for the Emergency Diesel Generator.. A NCV was  :

identified for failure to monitor the waste gas decay tanks as required. '

04.2 Unit 1 Steam Generator B Tube Leak Indication

a. Insoection Scooe

On August 30, 1996, at approximately 5:00 p.m.. Unit 1 operators

responded to indications of a SG tube leak on the B SG. The inspector

responded to the control room to monitor the plant indications and the i

operators response to the problem.

b. Observations and Findinas

Initial indications of the tube leak were via annunciation of EMF-33.

Condenser Air Ejector Exhaust Radiation Monitor, followed by indications

of a change in the N-16 (Nitrogen 16) monitor for the B SG. The B loop

N-16 monitor (on main steam line B) indicated an approximate 20 to 25

,

Enclosure 3

._ _ ___

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

,

a

~

l

4-

'

gpd leakage. Immediate operator response to the problem included:

entered AP/1/A/550/10. Rev.2. Loss of ND or ND system Leakage: initiated  ;

Emergency Coordinator for event: initiated trending of affected

'

radiation monitors including SG blowdown: and initiating RCS leakage

! calculations and chemistry sampling. Operator reviews of other control

l board parameters were performed and no other indications of tube leakage  :

was observed. At approximately 6:30 p.m. , chemistry sampling confirmed

'

,

that the leakage in the B SG and was approximately 5.8 gpd. TS '

3.4.6.2.c requires that RCS leakage through any one SG be limited to 500

gpd. At the time of the event. the licensee's administrative limit (ie.

l to evaluate potential shutdown of the unit) was 50 gpd: therefore, no  ;

other immediate actions were required.  !

! Other activities observed by the inspectors included the continued

monitoring of the Unit 1 tube leakage via chemistry sampling and leakage

calculations through the enri of the assessment )eriod. The leakage

estimate remained at approximately 6 GPD throug1 the end of the period.

The inspector considered that the monitoring was performed in a

conservative manner and of a higher frequency than that required by

plant procedures. Management concern with the problem was apparent

The McGuire Unit 1 SG's are scheduled to be replaced during a refueiing

outage scheduled to begin February 1,1997.

c. Conclusion

The inspector concluded that the operators response to and subsequent

monitoring of the Unit 1 SG B tube leakage was good.

08 Miscellaneous Operations Issues (92901) j

08.1 (CLOSED) LER 50-370/95-01 Past Inocerability of Unit 2 Containment

Penetrations: On February 8,1995, the hcensee determined that the

degraded piping at the Excess Letdown Heat Exchanger had rendered the

associated penetrations 2-M2117 and 2-M2118, inoperable. The i

penetrations depend on the piping integrity to act as a second boundary i

instead of having a redundant isolation valves. Because the crack was l

located in a section of component cooling water piping between the l

penetrations, the licensee determined that the loss of component cooling

water system integrity may have prevented the penetrations from i

'

fulfillment of their safety function.

The inspectors reviewed and evaluated the licensee's corrective actions

and determined that the licensee's actions have been completed in

accordance with the established schedule. The corrective actions

included extensive ultrasonic testing of the component cooling water  !

system piping and adjustments to system water chemistry to reduce tne

l

Enclosure 3

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

- . -. - .- -

.

.

5

likelihood of additional nitrate induced intergranular attack. Based on

the inspectors evaluation of the corrective actions and the absence of

additional component cooling water system piping failures attributed to

stress corrosion cracking, the inspectors concluded that the licensee's

actions were appropriate. This item is closed.

08.2 (CLOSED) LER 50-369.370/95-04: Manually Initiated Actuation of Both

Unit 2 Motor Driven Auxiliary Feedwater Pumos Due to Loss of Auxiliary l

Steam Suoolv to the Main Feedwater Pumo Turbine: This LER documented

the loss of steam flow from the Auxiliary Electric Boilers to Unit 2

resulting in reduced main feedwater pump output. J

Corrective actions included revisions to the Breaking Vacuum procedure

and procedures OP/2/A/6100/02, Controlling Procedure for Unit Shutdown

and OP/0/B/6250/07A, Auxiliary System Alignment. The inspector verified

the revisions to these procedures were adequate to correct the

deficiency. This LER is closed. l

II. Maintenance

M1 Conduct of Haintenance

M1.1 General Comments (61726 and 62703) i

1

a. Insoection Scope

The inspectors observed all or portions of the following work

activities:

. PT/2/A/4204/01 RHR Pump Performance Test

. IP/0/A/3250/12 Train A Diesel Sequencer Timer Calibration

. PT/1/A/4350/17 EDG Fuel Oil Transfer Pump Performance

Test

. PT/2/A/4600/01 RCCA Movement Test

. PT/0/A/4601/08 SSPS Train B Periodic Test With NC System

Pressure > 1955 PSIG

. PT/2/A/4350/15 Diesel Generator Periodic Test

. PT/2/A/4202/04 Spent Fuel Pool Pump 2B Air Handling Unit

Performance Test

. PT/0/A/4457/01 Control Room Chilled Water Pump #2

Performance Test

. IP/0/A/3050/13 RWST Class 1E Level Transmitter

Calibration

Enclosure 3

1

"

!

-

t

-

i

6 )

b. Observations and Findinas

The inspectors witnessed selected surveillance tests to verify that

approved procedures were available and in use, test equipment in use was

calibrated, test prerequisites were met, system restoration was

completed, and acceptance criteria were met.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Reactor Trio Bvoass Breaker 2B

a. Insoection Scooe

During Solid State Protection System functional testing, the P-4 Turbine

Trip on Reactor Trip interlock on the Unit 2 B Train Bypass Reactor Trip

breaker (RTB) failed to function as expected. The licensee was in the

3rocess of verifying a direct short circuit across a closed contact;

lowever, resistance measurements were too high to be indicative of a

direct short. The high resistance values indicated that the contact was

not closed as expected. Since the contacts associated with the P-4

circuit could not be visually examined with the breaker racked in, the

licensee terminated the test, racked in the Train B normal RTB. and

removed the bypass RTB for inspection. Once the Train B Main RTB was

racked in and closed, the B Train was declared fully operable.

b. Observations and Findinas

After removal of the bypass RTB from the cubicle, no visible damage was

identified however, circuit resistance measurements continued to

indicate higher than ex>ected. The breaker was quarantined for further

evaluation and troubles 1ooting. In an effort to isolate and identify

the open contact, the licensee measured resistances throughout the

circuitry including the secondary contact disconnect assembly. The

licensee concluded that the open contact was most likely located

internal to the auxiliary conta,t assembly block. The licensee was

unable to confirm this conclusion, because during the troubleshooting

activities. the high resistance measurements returned to normal. The i

licensee removed the auxiliary switch assembly for additional analysis I

and a new assembly was installed and tested on the breaker in accordance

!

,

l

Enclosure 3

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

-

,

'

a .

7

. with work order WO96062149. The breaker was verified to respond

i properly and was returned to its ) retest cubicle position. The licensee

>

postulated that the cause of the ligh resistance was a poor connection

through the auxiliary switch contact. The licensee stated that the

'

resistance measurements observed were not indicative of an open circuit:

however, it did exhibit a higher than expected resistance.

As a result of the surveillance finding, the licensee concluded that

when the breaker was in the connect position, the P-4 interlock was not

operalle through B Train (P-4 interlock generates a turbine trip on a

reactor trip). Although the turbine trip on reactor trip would not have

functioned, this function is a non-safety-related function to prevent

overcooling of the reactor coolant system and the auxiliary switch

, contact associated with the trip circuitry had no impact on the bypass

i RTB's ability to open upon receipt of a manual or automatic reactor trip

signal.

c. Conclusions

The inspectors reviewed the licensee's response to the surveillance test

finding and determined that the licensee's actions were appropriate and

completed within a reasonable time. The inspectors evaluated the

potential reportability of this test failure and determined that since

this failure did not involve a failure of the shunt or undervoltage

coils, the failure was not reportable. The inspectors also recognized

increased licensee efforts to resolve the issue in a timely manner.

M7 Quality Assurance in Maintenance Activities (92903)

M7.1 Inadequate Electrical Isolation of Post Accident Monitoring Circuitry

a. Insoection Scooe

On June 6. while troubleshooting the operator aid computer point for RCS i

wide range cold leg temperature the licensee determined that a minor l

modification implemented in the mid 1980s to ensure proper isolation of I

the safety-related post accident monitoring instrumentation from non- ,

safety circuitry was not properly completed. The original Nuclear

Safety Modification (NSM) required the addition of isolation devices and '

assecuted input and output wiring changes.

b. Observation and Findinas

An investigation by the licensee revealed that the output wiring changes

were not adequately implemented resulting in improper isolation of the

PAM recorder and computer point. Use of the wide range cold leg ,

temperature indication is referenced both in abnormal and emergency  !

operating procedures. Station FSAR section 1.11.5.1.3.1. requires that

for each process variable the recorded channels be enhanced through the

addition of isolators such that the control board recorders will not

l

Enclosure 3 ,

,

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

'

..

l

-

.

8

share isolators with the non-safety plant computer. The licensee

promptly completed the modification and successfully performed

functional testing.

c. Conclusions

The inspectors questioned why implementation instructions and quality ,

assurance verifications did not ensure the modification was properly l

installed. The inspectors reviewed the engineering instructions and l

noted deficiencies that could have contributed to improper installation

of the isolators. The inspectors reviewed the licensee's corrective ,

action and noted that adequate controls were currently in place to i

prevent recurrence. The inspectors verified that other similar

modifications were installed properly. In addition to the above. the

inspectors questioned the licensees determination of past operability i

and reportability of the issue. Based on the above. the ins)ectors will j

continue to evaluate the issue via URI 50-369.370/96-07-03. )AM Recorder l

Isolator Wiring Modification. Resolution of this issue will be based on '

determination of root cause, additional analysis of the significance of l

the event, and other items as discussed.

'

III. Enaineerina

E2 Engineering Support of Facilities and Equipment (37551) j

E2.1 Engineering Evaluation of Letdown Orifice Isolation Va'lve

a. Insoection Scop.g

The inspector reviewed the licensee's assessment of letdown orifice

isolation valve 2NV-458A operability and the compensatory measures

established for this leaking valve.

b. Observations and Findinas

During the inspection period valve 2NV-458A was determined to have seat

leakage. The licensee identified this problem during an attempt to swap

letdown orifices to reduce radiation levels in the Unit 2 Lower

Containment Pipe Chase for a containment entry. The licensee evaluated

operability of the valve problem with respect to the containment

isolation function of the valve and determined that the isolation

function was operable. Based on NRC questioning if additional

operability evaluations were needed for other scenarios, the licensee

identified a second evaluation was necessary to evaluate the potential

effects of high temperature letdown fluid passing through the tube side

of the LDHTEX and heating the KC system shell side (non-essential

header). The KC system Auxiliary Building Non-essential header is

isolated by a safety injection signal. The evaluation concluded that

the safety-related portion of the KC system and associated equipment

would not be impacted by steam voiding which could occur in the

Auxiliary building non-essential header at the LDHTEX.

Enclosure 3

J

.

.

-

9

The licensee determined that the containment inlation function of the

valve was operable. The isolation of the piping was also considered

operable. but degraded. Compensatory measures were subsequently

established to mitigate the possible consequences of this degraded -

condition.

c. Conclusion

The inspector reviewed the licensee evaluation of the valve leakage.

The inspector determined that the evaluation was conservative: however.

NRC questioning resulted in more in-de]th operability review.

Compensatory measures planned and esta)lished were adequate.

E7 Quality Assurance in Engineering Activities (37551, 92903)

F7.1 Auxiliary Feedwater System Temperature Monitoring

a. Insoection Scooe

On July 19, while investigating Unit 1 auxiliary feedwater injection

line temperature alarms, the licensee determined that the RTD

temperature indications were non-conservative. -The RTDs were reading

30-40 degrees less than the actual piping temperature measured using

portable monitoring equipment. The RTD s installed in response to

Generic Letter 88-03. Steam Binding of Auxiliary Feedwater Pumps, had

been used to measure auxiliary feedwater system piping temperatures to

detect the presence of steam voids that could lead to steam binding of

auxiliary feedwater pumps. These RTDs continuously monitor and provide

computer alarms to warn control room operators of higher than expected

system temperatures. Operators are directed to take specific actions

based on high piping surface temperatures. The licensee subsequently

determined that the installed RTDs were not the correct type. They were

intended for use in a thermowell rather than a strap-on surface mounted

application.

b. Observation and Findinas

The licensee implemented compensatory measures to monitor piping surface

temperatures once daily during the period of peak ambient temperatures

using a' portable hand held measuring device. However, the inspectors

noted that the licensee did not proceduralize the temperature monitoring

process to ensure consistency in the technique used to gather piping

tem]erature data and initially used less sensitive temperature measuring

pro)es to collect data. The licensee initiated a temporary modification

to change an RTD on the piping with the hottest temperatures to a new

strap-cn surface mounted type correct for the application.

Enclosure 3

J

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

,

'

.

.

'

10

'

Following installation, on August 5,1996, the readings from the new RTD

4 showed piping temperatures in excess of the procedural temperature

limits recuiring operator action. The temperature exceeded the piping

design anc saturation temperature of the system, prompting the licensee

4

to conclude that steam voids existed in the piping. The presence of

j steam voids could create a potential for water hammer and subsequent

pipe damage.

!

~

As a result, operators immediately declared the 1A MDAFW pump

inoperable. Subsequently, the TDAFW pump was also declared inoperable.

Control room operators immediately took actions in accordance with

procedures to cool the piping. These actions included closing the

affected line isolation valve and running the AFW pumps.

Compen.3 tory measures were subsequently revised to monitor the CA pump

discharge piping once per shift to ensure that the temperature was below l

required limits.  !

The inspectors reviewed the operability determinations made to address

the identified steam void pro)lems. To validate their o)erability I

decision, the licensee conducted a test to demonstrate tlat no water

'

hammer would result even with the presence of steam voids. The steam

voiding initially was determined to be caused by direct heating of the

CA injection check valves from CA tempering flow and some minor back

leakage through the check valves. To create the test conditions the

licensee allowed the CA piping to heatup and create steam void

conditions. The licensee then o)erated the motor driven CA pump with

the CA isolation valve closed. T1e licensee did not observe any

indications of a water hammer event.

The inspectors reviewed the evolution and determined that although the

licensee had conducted some preliminary technical evaluations prior to

conducting the test, an inadequate 50.59 evaluation was performed to

determine whether or not an unreviewed safety question existed. The

licensee )erformed the test and demonstrated that no water hammer would

occur wit 1 the presence of steam voids. The licensee also subsequently

conducted an 50.59 evaluation to confirm that no unreviewed safety

question existed under the test conditions. In addition, the inspectors

questioned the licensee concerning continued operation with steam

voiding in the auxiliary feedwater piping. As a result, the licensee

expanded the evaluation and concluded that with the presence of steam

voiding an unreviewed safety question did not exist.

The inspectors noted other discrepancies. Updates to the FSAR were not

performed to reflect the installation of the RTDs and CA system drawings

depicting placement of the RTDs were not consistent.

The licensee conducted an evaluation and determined that despite

exceeding piping design temperatures, the piping was operable. The

inspectors reviewed the evaluation and concluded it was adecuate. The

licensee conducted ultrasonic examinations of the piping anc determined

that the extent of voiding in the piping was greater than the original

estimate. The cause of the voiding was determined to be backleakage

Enclosure 3

.

- _ _ . -_.

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

!

.

-

.

i

11

through the injection line check valves. As a result, additional

i compensatory measures were implemented to maintain system operability.

4 By the end of the ins)ection period. the licensee had replaced all

'

existing RTDs with tie new strap on surface mounted type. The licensee

also increased the OAC alarm setpoints and revised o)erating procedures.

4

The inspectors conducted field walkdowns of the new RTD to verify

i correct installation. In addition, the licensee began engineering

4 evaluations to eliminate tempering flow in the CA injection line. This

! function will also be permanently eliminated.during the upcoming SG

j replacement projects on both units.

l

a

c. Conclusions

The inspectors concluded the licensees immediate corrective action was

good. Corrective action such as replacing the RTDs and evaluation of

i the elimination of tempering flow were also good. However, some

deficiencies in problem assessment caused delays in the formulation and

'

.

implementation of adecuate compensatory measures and problem resolution.

The inspectors concluced that the licensee installed the wrong type RTDs

which deviated from the response to commitments for Generic Letter 88-

03. Steam Binding of Auxiliary Feedwater Pumps to continuously monitor

i the discharge piping, provide alarms. 0AC graphics and applicable

procedures to prevent steam binding of auxiliary feedwater pumps.

'

I In addition initial compensatory measures to manually take AFW piping

'

temperatures were inadequate due to poor technique and/or wrong

temperature ) robe application. The inspectors noted that the licensee

maintained tie requirements to monitor piping by touching AFW pump  :

piping during NLO rounds. j

i

l The failure to comply with the requirements of this commitment is

i identified as a Deviation. 369. 370/96-07-04 Failure to Comply with

l Commitments in Response to Generic Letter 88-03. Steam Binding of

j Auxiliary Feedwater Pumps.

! The inspectors also determined that the licensee's failure to perform an ,

adequate 50.59 evaluation to fully evaluate the effects of AFW system i

! steam voiding prior to conducting a test was a Violation. 50-369/370.

96-07-05. Failure to Perform a 50.59 Evaluation prior to Conducting a i

Test. The failure to update the FSAR to reflect the installation of the

'

i

i RTDs will be identified as an additional example of URI 96-04-02. FSAR

j Inconsistencies,

f

E7.2 Grinnell Hydraulic Snubber Desian Inadeouacies

1  :

! a. Insoection Scooe

} The licensee determined that hydraulic snubbers manufactured by Grinnell

! would not meet post accident environmental cualification specifications

! that included requirements for radiation anc temperature. Specifically,

j procurement specification MCS-1206.00-04-0003. Rev. 2 requires that the

snuobers ue capable of performing their safety function under radiation

i conditions equal to 7X10E8 rads and 350 degrees F.

Enclosure 3

!

l  !

i

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

.

.

'

1

.

3

1 12

,

b. Observations and Findinas

4 The manufacturer confirmed that the Grinnell snubbers re)lacement parts

that included seals, polycarbonate reservoirs and fluid lad not been

qualified for these environmental conditions. The hydraulic snubbers

. were designed to " lock up" and restrain the pipe movement during a

j dynamic loading condition. The snubbers also allow for slow movement

'

j caused by thermal expansion. The dynamic loading conditions include

events such as a Safe Shutdown Earthquake and pipe ruptures associated

I with a Main Steam Line Break (MSLB) or a Loss of Coolant Accident. The

licensee determined that the worse case dynamic loading conditions

occurred during a (MSLB) accident with lower containment temperatures

j exceeding 325 degrees F for more than 8 minutes. However, under these

accident dynamic loadings conditions, the snubbers immediately performed

.

the function to " lockup" and restrain the ruptured pipe. Subsequently.

the high containment temperatures resulting from the main steam line

.

pipe rupture cause a significant distortion of the polycarbonate

!

reservoirs containing the hydraulic fluid. This results in some

'

leakage. The licensee also determined that despite leakage and

subsequent increase in fluid viscosity caused by post accident

conditions, the snubbers would function to allow thermal expansion of

l' the ruptured piping. The ins)ectors reviewed the operability

determination and concluded tlat it was adequate. The inspectors also

performed an inspection of selected safety systems to examine snubbers

for existing defects and snubber inoperability. No deficiencies were

! identified.

1

c. Conclusions

The licensee determined that although the Grinnel snubbers have not been

qualified to meet the environmental accident conditions per McGuire's

4 procurement specification. the snubbers will perform their design

,

'

function and are acceptable. The licensee is currently evaluating

changes to procurement specifications. pipe support and restraint design

, specifications, and is revising the FSAR to clarify the snubber post

i accident environmental temperatures and radiation level requirements.

'

In addition, the vendor is currently evaluating whether a Part 21

j notification should be issued on the subject.

4

E8 Miscellaneous Engineering Issues (92902)

'

E8.1 (CLOSED) URI 50-369.370/96-06-04: Personnel Airlock Leakaae Detection

'

,

System Desian Deficiency: The inspectors evaluated the licensee's

res)onse to deficiencies identified in the airlock seal automatic

leacage detection system deeign to ensure pro)er performance of the

upper and lower personnel ai r locks for both Jnit 1 and Unit 2 personnel

!

airlocks. The Volumetric, Model 14330 Automatic Leakage Rate Monitor

4 (LRM) had been declared inoperable due to design deficiencies discovered

i during bench testing. The automatic LRM would provide accurate door

'

, seal leakage measurements up to the calibrated maximum flow range value

(1000 sccm) but was found to count back during overrange conditions.

I

J

Enclosure 3

~

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

'

.

,

.

'

.

l 13

,

i

Once the LRM was declared inoperable, the licensee performed manual

airlock door seal testing on a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> frequency to satisfy TS i

requirements. '

The licensee contacted the equipment manufacturer to discuss options to

ll

correct the equipment deficiency. The vendor recommended replacement of

the flow sensors. Once the replacement aarts were procured. the

licensee implemented Minor Modification iGMM-8568 to install the

{ replacement components in each of the LRMs. The modification was tested

and functioned properly up to 2000 sccm. The Volumetrics units were

! then declared operable. The airlock was also determined to have been

. past o)erable. The licensee completed reviews of previous manual

i' airlocc seal test data and confirmed that actual leak rates were well

below the maximum calibrated range of the system and the leakage values

did not approach overrange conditions.

The inspectors concluded that testing of the equipment following the

original installation was not adequate. However, based on the

licensee *s identification of this design defect during bench testing,

the prompt corrective action taken to ensure equipment operability, and

the perceived safety significance, the inspectors determined that this

licensee-identified and corrected violation will be treated as a Non-

Cited Violation. 50-369.370/96-07-06: Personnel Airlock Leakage

Detection System Deficiency, consistent with Section VII.B.1 of the NRC

Enforcement Policy.

E8.2 (CLOSED) URI 50-369.370/96-06-01: Failure Analysis for 1B EDG Fuel Line

Failure: During the previous inspection period, on June 19. 1996, the

licensee experienced a failure of the 4R cylinder fuel line on the IB

EDG. The subject URI was identified to review the licensee's root cause

evaluation of the failure to determine the adequacy of the corrective

actions taken for all the EDGs. On July 18, 1996. the licensee issued a

root cause evaluation report of the IB EDG fuel line failure on the 4R

cylinder. The failure was attributed to tube pullout of the 4R cylinder

fuel injection line to fuel pump connection. Specifically, the report i

concluded the line had ejected from the ferrule connection due to I

inadequate crimping of the ferrule to the tube. All the fuel lines on

the Unit 1 EDGs had been u> graded to a new double-walled tube design in i

December 1995 to prevent t1 rough wall crack propagation. The Unit 2

EDGs fuel lines were previously replaced (all but four were upgraded i

double-wall) during earlier unit refueling cycles and had not '

experienced any failures. Corrective actions were developed to recrimp i

all a>plicable EDG fuel lines on Unit 1 and the four selected fuel lines '

for t1e Unit 2 EDGs. These actions were scheduled to occur concurrent

with the routinely scheduled EDG outage days (ie. one EDG per month) to

minimize unavailability. ,

l

The proposed recrimping schedule was based. in part, on a perceived

ability to predict a failure of the lines via analysis of cylinder i

exhaust temperature. Specifically, a review of historical exhaust

temperature data prior to the first failure indicated that the 4R j

cylinder had been experiencing a slow decrease in temperature which was  :

an indication of a small, undetectable fuel leak. Secondly, the

Enclosure 3

.  ;

-

.

14

I

licensee had previously performed a torsional analysis evaluation on the ,

McGuire Nordberg EDG crankshafts which concluded that operation of the

EDG could continue with the failure of a cylinder fuel line. The study 1

indicated that the fuel sup)1y to a failed cylinder could be shut off l

and with the exception of t1e number 1 cylinder (furthest from the  !

flywheel) the EDG would perform adecuately under full load. '

Additionally, the licensee performec a visual inspection of all the fuel

lines with no evidence of pullout or misalignment observed.

During the current inspection period on July 30. 1996, the licensee

experienced an additional failure of the 1B EDG 4R cylinder, prior to

performing the recrimping as discussed above. Based on the second

failure at the same location, the licensee expanded their original root

cause investigation process and obtained the services of two separate

vendors to act as oversight for the failure analysis and to provide

technical expertise. The second revision to the root cause analysis

concluded that the most likely cause of the second failure was improper

crimping of the sleeve onto the fuel line, possibly aggravated by some

pressure increase at the fuel pump outlet. The increased fuel pressure

may have been caused by slight fouling of the injector nozzles.

Additional contributing factors may have included: reduced delivery ,

valve holder assembly torque introduced as a corrective action to PIP 1- l

M94-1022 which reduced the ability to make-up for the inadequate

manufacturing crimping process: and excessive fuel line extending past

the ferrule which could cause the line to bottom into the delivery valve

heider. The inspectors noted that the licensee also concluded that the i

monitoring of cylinder exhaust temperatures was not as good of a failure i

indicator as previously expected.  ;

Based on the revised root cause, the licensee performed significantly

expanded their corrective actions. These PORC reviewed actions l

included:

'

-

For the 1B EDG, fuel lines were recrimped, fuel line ends were

machined for pr Sper ferrule positioning, and a 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> run ,

performed to verify the recrimping process. '

-

Replaced both injector and fuel pump on the 4R cylinder and

inspected the two additional injectors for contamination. No

contamination was identified.

-

Ferrule connections and the crimping process was reviewed by an

industry expert.

- Removed, recrimped, machined tube ends, and reinstalled all fuel

injection lines for the 1A, 2A, and 2B EDGs in an expedited

manner.

The inspectors reviewed the licensee's final root cause analym:; report

dated August 30. 1996. and discussed the corrective actions and

conclusions with the licensee. Based on the inspectors monitoring the

implementation of the subsequent corrective actions, attending PORC

reviews of the event, and visually inspecting the fuel line repairs the

Enclosure 3

,

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

i

.

. .

15

1

4

'

inspectors concluded that the current root cause review was thorough.

However, based on the occurrence of the second failure. the inspectors

also concluded that the corrective actions for the first fuel line  :

failure were inadequate to preclude an additional failure from l

occurring. This issue will be identified as Violation 369. 370/96-07- l

07. Failure to take Adequate Corrective Action for EDG Fuel Line

Failure. The URI concerning this issue is closed. )

IV. Plant Support

!

t R1 Radiological Protection and Chemistry Controls (71750)

4

Plant support activities were observed and reviewed to er.sure that

programs were-implemented in conformance with facility policies and

I

procedures and in compliance with regulatory requirements. Activities

reviewed included radiological controls, physical security, emergency

j preparedness, and fire protection.

! R1.1 Radiation Monitors Survey

!' The inspectors performed a survey of TS radiation monitors. The

inspectors reviewed radiation monitor unavailability data. The data

showed that the unavailability for TS radiation monitors was low. All

'

radiation monitors were operable at the time of the survey. The

i inspectors verified the operability of the TS related radiation monitors

, by reviewing control room logs. TSAIL entries and control room

indications.

l The inspectors concluded that TS radiation monitor unavailability for

l the period reviewed was good.

P1 Conduct of EP Activities

q Pl.1 EP Drill Observation (71750)

l a. Insoection Scooe

!

The inspectors reviewed an Emergency Table To) Exercise Scenario that

was scheduled to be performed on August 5. T1e scenario was found to be

very realistic and re3 resented portions of a plant condition that

"

actually occurred on Jnit 1 during the month of June 1996. On August 5. l

the inspectors toured the Technical Su) port Center. Control Room, and

i the Operational Support Center while tie Emergency Exercise Scenario was ,

being conducted.

b. Observations and Findinos

j The Table Top Exercise began with Unit 1 at 100% power and both EDGs

inoperable. The 1A EDG could be available in 10-12 hours and 1B EDG was

expected to be back in service in 4-5 hours. A severe thunderstorm was

in the vicinity of the plant. A lightning strike resulted in a total

loss of offsite power for Unit 1. With both Unit 1 EDGs inoperable and

Enclosure 3

- - - . - _ . -

.

I

e

16

tagged out, a loss of all AC power was experienced on Unit 1. The

reactor tripped and plant conditions worsened until a " Site Area

Emergency" was declared. During the exercise. )lant conditions existed

that required the Standby Shutdown Facility (SS ) to be activated. The  !

critical time for activating the SSF is limited to a maximum time of 10

minutes. The basis for this time limit is to assure that the reactor

coolant pumps seals do not fail. The inspectors noted that it took 11

minutes after notification before the SSF was properly activated.  !

An exercise critique was conducted by the licensee drill evaluators

after the drill was completed. The evaluators discussed the

circumstances and conditions that resulted in the SSF not being

activated within the allowed time. Plant management directed operations

to revise the Controlling Emergency Procedures and to require activation

of the SSF at an earlier step in the procedure. Also, engineering was

directed to determine if the Westinghouse pump seals may have a grea'.er

failure time margin for the seals,

c. Conclusions

The inspectors concluded that the training performed in support of i

emergency 3reparedness was generally professional and thorough. The

scenario clallenged the operators and was effective in accomplishing

espected results. However, during the drill a weakness was identified

in Operations ability to activate the Standby Shutdown Facility within

10 minutes as required by plant procedures to preclude potential reactor

coolant pump seal damage during a loss of all AC. The ins)ector will

continue to evaluate the significance of the problem via I I 50-

369.370/96-04-05. which was previously identified regarding the

licensee's ability to man the SSF within the allotted time.

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 September 10. 1996. The l

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. )

!

Enclosure 3

i

w a

i

.

.

.

17

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Boyle, J. , Manage". Safety Assurance (Acting)

Cross R., Regulatory Compliance

Geddie. E., Manager. McGuire Nuclear Station

Herran, P., Manager. Engineering

Johnson, G., Training. Nuclear Generation Department

Loucks L., Radiation Protection Manager (Acting)

McNeekin. T., Vice President. McGuire Nuclear Station

Nazar. M., Superintendent. Maintenance

Silver. J.. Manager. Operations Support

Snyder J.. Manager. Regulatory Compliance

Thomas, K., Superintendent. Work Control i

Thrasher. J., Manager Modification Engineering i

Travis B., Manager. Mechanical / Civil Equipment Engineering

Young. A. . Engineering. Nuclear Production Department

NRC

G. Maxwell. Senior Resident Inspector. McGuire

S. Shaeffer. Senior Resident Inspector McGuire

M. Sykes Resident Inspector. McGuire

G. Harris Resident Inspector McGuire

S. Rudisail. Project Engineer RII

l

l

!

i

Enclosure 3

x . -.

i

-

.

l

.

18

INSPECTION PROCEDURES USED

IP 92901: Operations Followup

IP 92902: Maintenance Followup

IP 92903: Engineering Followup

IP 93702: Prompt Onsite Response to Events at Operating Power Reactors

IP 71707: Plant of Operations

IP 71750: Plant Support

IP 62703: Maintenance Observations

IP 61726: Surveillance Observations

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

Identifying Problems

IP 37551: Onsite Engineering

ITEMS OPENED. CLOSED, AND DISCUSSED

Ooened

VIO 50-369.370/96-07-01 Failure to Perform Surveillance on Emergency

Diesel Generators

NCV 50-369.370/96-07-02 Failure to Monitor Waste Gas Tank j

URI 50-369.370/96-07-03 PAM Recorder Isolator Wiring Modification

DEV 50-369.370/96-07-04- Failure to Comply with Commitments in Response l

to Generic Letter 88 03. Steam Binding of .

Auxiliary Feedwater Pumps i

!

VIO 50-369.370/96-07-05 Failure to Perform a 10 CFR 50.59 Evaluation  !

Prior to Conducting a Test

NCV 50-369.370/96-07-06 Personnel Airlock Leakage Detection System

Design Deficiency

VIO 50-369.370/96-07-07 Failure to Take Adequate Corrective Action for

EDG Fuel Line Failure

Closed

i

LER 50-370/95-01 Past Inoperability of Unit 2 Containment

Penetrations

LER 50-369.370/95-04 Manually Initiated Actuation of Both Unit 2

Motor Driven Auxiliary Feedwater Pumps Due to

Loss of Auxiliary Steam Supply to the Main

Feedwater Pump Turbine

URI 50-369.370/96-06-04 Personnel Airlock Leakage Detection System

Design Deficiency

Enclosure 3

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

._ _.

.  :

19

URI 50-369,370/96-06-01 Failure Analysis for 1B EDG Fuel Line Failure

Discussed

URI 50-369.370/96-04-02 FSAR Inconsistencies

LIST OF ACRONYMS USED

AFW Auxiliary Feedwater

DEV Deviation

ECCS Emergency Core Cooling System

EDG Emergency Diesel Generator

EP Emergency Preparedness

ESF Engineered Safety Feature

FSAR Final Safety Analysis Report

gpd gallons per day

IFI Inspector Followup Item

IR Inspection Report

KC Component Cooling System

LER Licensee Event Report

LRM Leakage Rate Monitor

MDAFW Motor Driven Auxiliary Feedwater Pump

NCV Non-cited Violation

NLO Non-licensed Operator

NRC Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

NSM Nuclear Station Modification

OAC Operator Aided Computer

PAM Post Accident Monitoring

PORC Plant Operations Review Committee

PIP Problem Investigation Process

PT Performance Test

RCCA Rod Control Cluster Assembly l

RCP Reactor Coolant Pump

RCS Reactor Coolant System  ;

R0 Reactor Operator l

RP Radiation Protection '

RTB Reactor Trip Breaker j

RTD Resistance Temperature Detector

RWST Refueling Water Storage Tank .

SFP Spent Fuel Pool )'

SG Steam Generator

SR0 Senior Reactor Operator

SSF Standby Shutdown Facility

SSS Standby Shutdown System 1

TDAFW Turbine Driven Auxiliary Feedwater Pump

TS Technical Specifications  :

TSAIL TS Action Item List

URI Unresolved Item i

VIO Violation

Enclosure 3

- _ _ _ _ - , _ _ . ,