ML20136C095

Insp Repts 50-352/96-10 & 50-353/96-10 on 961217-970203. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML20136C095
Person / Time
Site:	Limerick
Issue date:	03/06/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20136C086	List: ML20136C081 ML20136C089 ML20136C095
References
50-352-96-10, 50-353-96-10, NUDOCS 9703110260
Download: ML20136C095 (32)

See also: IR 05000352/1996010

Text

_.

4

I

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

License Nos.

NPF-39

NPF-85

Report Nos.

96-10

96-10

Docket Nos.

50-352

50-353

Licensee:

PECO Energy

~ Correspondence Control Desk

P.O. Box 195

Wayne, PA 19087-0195

Facility Name:

Limerick Generating Station, Units 1 and 2

Inspection Period:

December 17,1996 through February 3,1997

Inspectors:

N. S. Perry, Senior Resident inspector

F. P. Bonnett, Resident inspector

P. D. Swetland, Project Engineer

G. C. Smith, Senior Physical Security inspector

Approved by:

Walter J. Pasciak, Chief

Projects Branch 4

9703110260 970306

PDR

ADOCK 05000352

G

PDR

. - .

-.

_

- - ,

-

.

.

-.

- -

.

-

.

--

.

- -

.

.

EXECUTIVE SUMMARY

Limerick Generating Station, Units 1 & 2

NRC Inspection Report 50-352/96-10,50-353/96-10

.

This integrated inspection included aspects of licensee operations, engineering,

maintenance, ard plant support. The report covers a 7-week period of resident inspection;

i

in addition, it includes the results of announced inspections by a regional project engineer

and senior physical security inspector.

.

Operations

'

The combined response of the operations, maintenance, and engineering

departments to mitigate excessive air inleakage at Unit 2 was excellent. Plant

i

'

management's decision to shut down the plant to replace the expansion joint was a

.

safe and conservative action to mitigate a potential plant transient. (Section 01.2)

i

The system manager demonstrated a good awareness and understanding of the

plant impact that existed by the stator cooling water TCV controller setpoint

'

adjustment arm falling over. The system manager's actions prevented a potential

plant transient and scram. (Section 01.3)

,

l

Plant management made a conservative decision to shut down Unit 2 one day early

due to increasing unidentified drywell leakage rate. Operators conducted shutdown

,

activities well. (Section 01.4)

The root cause and corrective actions taken for a Unit 2 RCIC isolation were

i

'

appropriate. However, the inspectors were concerned that when personnel were

]

initially questioned concerning why the system was operable with pressure

j

transmitters apparently not verified operable, a good basis could not be provided.

$

The appropriate basis was communicated to the inspector later that day after

engineering personnel were contacted. The inspectors concluded that the basis for

declaring the RCIC system operable was not adequately documented in this

instance. Plant management has taken steps to ensure that the appropriate

personnel document bases as necessary prior to leaving the site. (Section 01.5)

The results of the . operations investigation and the corrective actions taken for a

Unit 1 emergency diesel generator (EDG) low fuel oil storage tank level were

reviewed. Operations management aggressively pursued an improved method for

reading the storage tank oil level, in order to make it easier for the operatore,

considering the current potential for adverse weather or lighting.

The D14 EDG was inoperable for approximately two months because appropriate

actions were not taken as required by technical specifications. At least four

instances were identified where operators had an opportunity to identify the low

tank level. Additionally, operations management was aware of the difficulties in

obtaining a consistent, reliable measurement, at least since 1992, and adequate

ii

. . - - -

_ - .-

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

- ... - - . -

l

.

J

l

-

)

corrective actions were not taken. Failure to take the actions required by Technical Specification 3.8.1.1 is a violation. (Section O2.2)

i

!

{

e

Several operator performance and procedure adherence problems occurred that

'

contributed to the inadequate control of two primary containment isolation valves

(PCIVs). Procedure weaknesses also affected the defense-in-depth controls. The

j

two PCIVs did not meet the technical specification for being sealed closed between

the time when the reactor exceeded 600 psig on December 13 until the time when

the breakers for the motor operators were de-energized on December 16. Because

'

the PCIVs were not properly sealed closed, the TS action statement requiring the

penetration to be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or the plant be in Hot shutdown in the

j

following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was

exceeded. Additionally, the requirements for Fire Safe Shutdown, as stated in the

UFSAR Table 9A-12, were not met. Management's evaluation identified the causes

of the event and has implemented corrective actions to address recurrence of the

'

$

event. This is a violation. (Section O3.1)

!

e

Limerick's problem identification and resolution programs were found to be

improved and effective. They have appropriate thresholds, are sufficiently critical,

and track actions to completion. There is strong management and oversight-

support through participative supervision, resource commitment, and high

expectations. Corrective action backlogs are managed to an acceptable level.

j

Station self-assessment reviews were very effective, having recognized and acted

upon all the discrepancies identified by the inspectors. The corrective action

- effectiveness reviews need to be more timely and critical, to assure interim

!

recurrences are prevented. (Section 07.1)

4

)

Maintenance

4

l

e

Routine maintenance and surveillance activities were conducted well and completed

j

with satisfactory results. (Sections M1.1 and M1.2)

i

j

e

The 18 month inspection and maintenance of the D13 EDG was performed well.

l --

The follow-up testing and repairs were effectively controlled and included a

significant level of engineering support. (Section M2.1)

'

Enaineerina

e

The engineering staff effectively supported the safe operation of the unit. A

thorough review of the condenser to turbine expansion joint condition and possible

failure mechanism resulted in a timely determination of the need for prompt

replacement. (Section E2.1)

e

Failure to meet a License Condition, which requires the implementation and

maintenance of all provisions of the approved Fire Protection Program, resulted in

an apparent violation. In the event of a significant fire in the main control room, the

auxiliary equipment room, or the cable spreading rooms, operators would need to

shut down both units from the Remote Shutdown Panels. Three safety relief valves

iii

.

.

(SRVs) would need to be operated to assist in achieving cold shutdown. The

shutdown analysis relies on the primary containment instrument gas (PCIG) system

to operate the SRVs for up to six hours; however, a review of actual PClG system

operation revealed that the system may only remain available for up to one hour.

This is an apparent violation. (Section E8.4)

Plant Sucoort

PECO Energy maintained an effective security program. Management support is

ongoing as evidencea by upgrades to the assessment system, renovations to

improve personnel flow in the personnel processing center, allocation of resources

for additional tactical, firearms and emergency medical technician training, and an

initiative that established a partnership with local law enforcement agencies for an

improved firearms range. The central and secondary alarm station operators were

knowledgeable of their duties and responsibilities and were not engaged in activities

that would interfere with their response functions. Security training was being

performed in accordance with the NRC-approved Training and Qualification plan and

management controls for identifying, resolving, and preventing programmatic

problems were effective. Protected area (PA) detection equipment satisfied the

NRC-approved Physical Security Plan commitments and security equipment testing

was being performed as required in the Plan. Maintenance of security equipment

was being performed in a timely manner as evidenced by minimal compensatory

posting associated with security equipment repairs. Based on inspector's

observations and discussions with security officers, the inspector determined that

they possessed the requisite knowledge to carry out their assigned duties and that

the training program was effective. (Sections S1-S7)

The loss of control of master keys is unresolved pending review of further

information as to the extent of the problem and its significance. (Section S8.2)

iv

_ .

-

-. -

.

. - .

..

.

'

i

1

Reoort Details

i

.

Summarv of Plant Status

Unit 1 began this inspection period operating at 100 percent power. On December 23,

,

operators reduced reactor power to 25 percent in response to a main generator stator

water cooling temperature control valve (TCV) controller failure. Maintenance technicians

j

repaired the valve controller and reactor operators restored the unit to full power the same

j

day. Otherwise, the unit remained at full power throughout the inspection period with

-

minor exceptions for testing.

Unit 2 was operating at 29 percent power at the beginning of this inspection period,

-

continuing with the startup that commenced on December 13. Operators were holding

power at 29 percent due to high condenser air inleakage that engineers found to be from a

degraded main condenser expansion joint. A temporary repair improved the inleakage

problem. The following describes the Unit 2 operational events during this inspection

period:

1

,

e

December 18

Operators manually shut down the unit from 47 percent to

begin a four day outage. Plant management decided to shut

down the unit to replace the condenser expansion joint.

,

Operators made the reactor critical on December 22 and

l

synchronized the generator to the grid on December 23.

December 24

Operators manually scrammed Unit 2 from 27 percent power '

af ter a ball joint located on the 2B recirculation pump motor-

generator scoop tube positioner controllinkage failed. The

,

failure caused an unexpected recirculation pump speed

increase, requiring a pump trip, which placed the unit in the

exclusion region of the power / flow map. Entry into the region

requires an immediate scram due to core thermal hydraulic

instability concerns. The operators made the reactor critical

l

later that day and synchronized the generator to the grid on

December 26. Unit 2 reached the maximum coastdown power

of 87.7 percent on December 27.

e

January 22

Operators reduced reactor power from 77 percent to 43

percent after an equipment operator reported a level drop in

the electro-hydraulic control (EHC) oil reservoir. A smallleak

from the No. 3 turbine control valve servo was identified as

!

the source. The operators restored power to 77 percent after

maintenance technicians reoaired the leak.

e

January 30

Operators shut down Unit 2 from 74 percent power to begin

the fourth refueling outage (2R04).

4

.

>

~e

- - - . .- _

-

__.-._ __

__

. -

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

. - ._- - - -

.

4

'

2

1, Operations

01

Conduct of Operations'

01.1 General Comments (71707)

Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing

plant operations. In general, PECO Energy's conduct of operations was professional and

safety-conscious. Operators conducted routine activities well. Operators demonstrated

good communication skills and control during several plant transients, including the Unit 1

power reduction to 25 percent due to the failed stator cooling water temperature control

valve (TCV) controller, the Unit 2 shutdown due to high condenser air inteakage, and the

,

2B recirculation pump runaway. Operators conducted start-up activities well at Unit 2

with the exception of operator errors surrounding the two primary containment isolation

valves found energized (Section 03.1).

01.2 Unit 2 Shutdown Due to Hiah Condenser Air inleakaae

a.

Insoection Scope (71707)

F

Control room operators manually shut down the Unit 2 reactor from 47 percent power on

December 18, due to a degraded condenser expansion joint that was causing excessive air

.

inleakage to the main condenser and high offgas flow. The operators restarted the unit on

December 22, after completion of a four day outage to replace the expansion joint. The

inspector reviewed the events surrounding the shut down, attended various meetings, and

discussed the event with key individuals.

!

'

b.

Observations and Findinas

I

'

During the unit start-up from the December 6 maintenance outage (see Inspection Report

50-352,353/96-09), operations personnel noted an excessive amount of flow in the

'

condenser offgas system. Condenser air inteakage indicated 246 standard cubic feet per

minute (scfm). The offgas system can process up to 300 scfm. Operators held reactor

power at about 20 percent while system managers and maintenance technicians

performed helium testing in the main condenser area to find the source of the leak. The

engineers identified the leak to be a tear in the expansion joint between the 2A main

condenser and 2A low pressure turbine exhaust.

A temporary repair consisting of nylon strips placed over the affected area of the joint and

supplying demineralized water to the seal trough reduced the air inteakage to 40 scfm.

However, engineering determined that the expansion joint was in danger of tearing further

,

causing a rapid loss of vacuum with little or no warning. Plant management therefore

,

' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized

reactor inspection report outline. Individual reports are not expected to address all outline

topics.

- .

.-

-

_

.

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

i

.

i

!

!

-

1

3

i

decided that the risk to continue plant operation with the degraded joint was not

warranted. The operators shut down the unit without incident.

c.

Conclusions

!

The comb lned response of the operations, maintenance, engineering departments to

mitigate the excessive air inleakage was excellent. Plant management's decision to shut

down the plant to replace the expansion joint was a safe and conservative action.

01.3 Power Reduction to 25 Percent Power - Unit 1

a.

Insoection Scope (71707)

Unit 1 reactor operators reduced power from 100 percent to 25 percent on December 23

due to a failure of the stator cooling water temperature control valve (TCV) controller. The

inspector reviewed and discussed the event with the system manager.

b.

Observations and Findinas

The stator cooling water TCV was controlling stator water temperature low outside the

normal operating band. The Fisher TCV controller was set to control at 43 degrees C and

actual temperature was being monitored at 38 degrees C. The operations department

initiated an action request to resolve the deficiency.

During the corrective maintenance activity, the system manager observed the friction clips,

that hold the setpoint adjustment in place, fall out of the controller. The setpoint

'

adjustment arm fell under its own weight resulting in the temperature setpoint being

increased. The system manager noticed system temperature increasing in response to the

setpoint change and immediately movad the setpoint adjustment arm back to its original

position, holding it in place until the reactor operators reduced unit power.

Maintenance technicians gaged the TCV while making repairs to the setpoint adjustment

assembly, then placed the controller and TCV in service. Unit operators restored unit

power to 100 percent without further incident.

The inspector determined that the potential for an automatic main generator runback and

reactor scram existed. Had the setpoint adjustment arm remained in the failed position,

stator cooling temperature would have increased to 81 degrees C, initiating a loss of stator

water cooling runback. Both recirculation pumps would have sequentially tripped after a

ten second time delay, requiring the operators to initiate a manual reactor scram. The

purpose of this runback is to quickly reduce load in anticipation of a pressure transient

caused by a generator load reject.

. c.

Conclusion

The system manager demonstrated a good awareness and understanding of the plant

impact that existed by the setpoint adjustment arm falling over. The system manager's

'

actions prevented a potential plant transient and scram.

.

-

.

.

--

-

-

- . - - -

-

-

.__

.

4

01.4 Unit 2 Shutdown for Refuelina Outaae (2R04)

a.

Inspection Scope (71707)

Unit 2 operators shut down the reactor at 4:00 p.m., on January 30, to begin the fourth

refueling outsge (2R04). The inspectors observed portions of the operator activities in the

control room and discussed the outage scope with the appropriate staff pmnnel,

b.

Observations and Findinas

Operators conducted activities during the Unit 2 shutdown well. The inspectors noted that

operators used the appropriate procedures when performing evolutions and that shift

supervision maintained a professional atmosphere in the control room at all times. The

inspector also noted that entries into the locked valve log were made at the appropriate

times.

Plant management made a conservative decision to shut down the unit one day early due

to increasing unidentified drywell leakage rate. Leakage had reached 4.0 gpm as indicated

in the control room, the Technical Specification (TS) limit is 5.0 gpm. Drywell leakage had

been steadily increasing since the unit restarted in December due to a degrading

mechanical pump seal on the 2A recirculation pump. Although the seal was suspected as

the source of the leak, the high leakoff flow annunciator had not alarmed. Plant

management's concern was that the leak would continue to degrade and increase to

exceed the TS limit while shutting down the unit on January 31.

After entering the drywell, engineers found a hole in the recirculation pump seal cover.

,

This caused the leakage to bypass the flow element and be collected in the floor drain

system. Had the drain line been intact, the leakage would have been identified, giving a

25 gallon totalleakage TS limit, and no concern to shutdown the unit early.

Management expects the outage to be completed within 21 days, but willincrease the

outage scope to include any emergent work that would impair the unit reliability during the

next cycle. The scope of 2R04 includes desludging of the suppression pool, replacement

of several main steam relief valves, installation of a main steam isolation valve

modification, modification to the low pressure coolant injection isolation valves, and

replacement of the 2A residual heat removal pump motor. General overhaul work will be

performed on the high pressure coolant injection and reactor core isolation cooling systems

and the high pressure turbine and main condenser.

c.

Conclusions

Plant management made a conservative decision to shut down the unit one day early due

to increasing unidentified drywellleakage rate. Operators conducted shutdown activities

well.

- -

-

.

9

5

01.5 Unexpected RCIC isolation - Unit 2

a.

Insoection Scoce (71707)

On December 22, at Unit 2, the reactor core isolation cooling (RCIC) inboard steam line

isolation valve unexpectedly received a low supply pressure isolation signal and closed, as

operators were warming the steam line. The inspector reviewed the circumstances

surrounding the event in order to determine the cause and its affect on declaring the -

system operable.

b.

Observations and Findinas

The investigation by plant personnel concluded that the cause for the isolation was residual

water remaining in the piping, which was the result of steam condensation during the plant

outage. Operations personnel opened the isolation valve fast enough to cause an

instantaneous pressure drop to be sensed by the instrumentation. Engineering personnel

'

concluded that the system was operable based on: 1) multiple trip units had a trip signal

in, so there was not an equipment problem; 2) after the isolation, the instrumentation was

reading accurately;-3) when the isolation valve was opened more slowly the second time,

the problem did not reoccur; and 4) the instrumentation calibration was verified to be

'

within established limits. Corrective actions for the event included adding a caution

statement to the appropriate RCIC and high pressure coolant injection (HPCI) procedures

concerning the effects of opening the isolation i alves too quickly during system

restoration.

c.

Conclusions

The NRC concluded that the root cause and corrective actions taken were appropriate.

However, the inspectors were concerned that when personnel were initially questioned

concerning why the system was operable with pressure transmitters apparently not verified

operable, a good basis could not be provided. The appropriate basis was communicated to

the inspector 1. iter that day after engineering personnel were contacted. The inspectors

concluded that the basis for declaring the RCIC system operable was not adequately

documented in this instance. Plant management indicated agreement with this conclusion,

and has taken steps to ensure that the appropriate personnel document bases as necessary

prior to leaving the site.

O2

Operational Status of Facilities and Equipment

O 2.1 Routine Plant Tours (71707)

The inspectors used Procedure 71707 to perform routine tours of the facility and also to

walk down accessible portions of engineered safety feature (ESF) systems:

High Pressure Coolant injection (HPCI) System - Unit 1

Residual Heat Removal (RHR) System - Unit 2

Emergency Diesel Generators (EDG)- Unit 1 and 2

.

.

.

6

Equipment operability, material cond; tion, and housekeeping were acceptable in all cases.

Several minor discrepancies were brought to management's attention and were corrected.

The inspectors identified no substantive concerns as a result of these walkdowns.

02.2 D14 EDG Fuel Oil Storaae Tank Level

a.

Inspection Scope (71707)

On December 31, an operations equipment operator (EO) discovered that the D14

emergency diesel generator (EDG) fuel oil storage tank oil level was below the technical

specification (TS) minimum required level. Plant management subsequently determined

that the D14 EDG had been inoperable for two months. The inspector reviewed the event

and the immediate corrective actions, observed tank level measurement activities,

independently verified the amount of fuelin the tank from the tank curve and analyses, and

discussed the event with plant personnel and plant management. Additionally, the

inspector reviewed the short term, and long term corrective actions taken.

b.

Observations and Findinas

The technical specification limit for fuel oil in the fuel storage system is a minimum of

33,500 gallons, which corresponds to a level of 9 feet 6 inches. The EO measuring the

'

D14 fuel oil storage tank oil level found it to be at 9 feet 1 inch. The low oil tank level

alarm had not come in as expected, prior to exceeding the TS minimum level. After

discovery, operations personnel independently verified that the D14 tank level was below

the TS minimum, declared the D14 EDG inoperable, ordered a fuel delivery, and verified

that the other seven EDGs had fuel oil storage tank oillevels above the TS minimum. The

D14 EDG was declared operable on January 1,1997, after the storage tank level was

brought to 9 feet 8 inches.

An investigation by operations personnel concluded that the low fuel oil storage tank level

had existed since November 2,1996. On that day, the EDG was being run for its 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

TS surveillance run. Fuel oil was delivered during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run, but the amount

delivered was insufficient and after the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run the storage tank level was

approximately 9 feet 4 inches. Records showed that the measured level after the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

j

run was 10 feet 61/2 inches; this level was not possible based on EDG consumption data

'

and run time, using the initial storage tank level, and the amount added by the delivery.

Subsequent to the November 2,1996, incorrect level measurement, the storage tank oil

level was incorrectly measured at least four times by different operators.

The operations investigation concluded that the root cause for the measurement errors was

operator error due to a challenging method for determining the storage tank oil level. The

fuel oil storage tank levelis measured by dipping the tank with a weighted tape measure.

The fuel oilis clear and very difficult to see clearly on the tape measure; this method is

more unreliable under adverse weather or lighting conditions. Contributing factors to the

incorrect readings included: the opr.rator readings were influenced by an expected oil level

based on the last measurement taken, which is recorded in the operators' office space; the

tank level switch was stuck preventing an alarm from annunciating in the control room;

and the tape measure is flexible ano finding the tank bottom can be difficult due to the

.-.

-. .

.

.

_.

.

. - .

.

.

',

7

location of a sump. Through interviews, operations management concluded that the

incorrect readings taken did not involve any willful intent to f alsify records.

'

Interim corrective actions included informing operators of the potential for obtaining an

incorrect tank level reading and that increased attention should be applied when obtaining

the tank oil level, and revising the appropriate procedures to require an independent tank

level reading until a more reliable method was implemented. PECO engineers redesigned

!

the dipstick used to obtain the storage tank level. This improved method was put in place

on February 3,1997. The redesigned dipstick measures the level without the need to find

,

the bottom of the tank; each storage tank has its own measuring stick which will hang

,

i

from, and measure from, the top of the tank fill connection. Additionally, the dipstick is a

wider stick, blackened to make it more easy to read, with the tape measure attached to it.

Each tank's new dipstick was independently calibrated to assure its accuracy. Finally, the

non safety related backup tank level switch that stuck was repaired and the other seven

'

EDG tank level switches were inspected; the cause of the stuck switch was corrosion.

The other switches were functioning but were degraded. Additional preventive

maintenance activities have been scheduled to ensure the instruments remain fur.ctional

until the reliability of the instruments is addressed.

Management concluded that the consequences for this condition were minimal. The

minimum TS required volume of fuel oilis based on providing an onsite supply of fuel oil to

support seven days of continuous operation of the EDG. The actual amount of fuel oilin

the storage tank for the D14 EDG was approximately 32,260 gallons; this would have

supported over six days of continuous operation of the D14 EDG. If fuel oil could not have

been delivered, there was excess fuel oilin the other three EDG storage tanks, and some

of this excess oil could have been transferred to the D14 EDG tank through the use of

permanently installed piping.

The inspector noted that the use of the tape measure has been previously noted as

cumbersome by the NRC in 1992 (Inspection Report Nos. 50-352/92-81 and 50 353/92-

81), where it was observed that, "the operator had trouble getting consistent readings and

,

had to check or sound the tank five times and use cloth to find the oillevelline." The

inspectors indicated, in 1992, that they were concerned that, " oil deposited on the edge of

the access port from repeated checks could cause the TS limit to be inadvertently

exceeded." An equipment operator indicated to the inspector that he had to dip the tank

three or four times to get a good reading due to the adverse weather (raining), and he

subsequently found that his reading was incorrect.

The inspector observed two measurements of the storage tank oillevel, by different

operators, using the same tape measure; the weather was clear but cold and windy. The

'

inspector noted that it was very difficult to get a good reading, and it would have been

extremely difficult at night or in precipitation.

The inspector discussed the interim corrective actions with operations management; the

interim corrective actions did not appear to adequately address the root cause or the

contributing factors. Although operators were informed of the potential for obtaining an

incorrect tank level reading and that increased attention should be applied when obtaining

the tank oillevel, the method of using the tape measure was not changed, and the

a

--

- - .

. .

- - .

. - .- = .

- -.-

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

i

1,

!

-

!

8

i~

the tank oil level, the method of using the tape measure was not changed, and the

]

Independent verification used the same tape measuring system. The inspector noted that

l

at least four consecutive, independent measurements were erroneously taken.

Additionally, the inspector noted that other means could have been used to verify the tank

'

!

level, such as using the localinstalled instrument or through the use of calculations, as

j

was done for the operations investigation. Since the new method for obtaining the tank

level was put in place in a relatively short period of time, the inspector agreed that the

4

!

interim corrective actions were acceptable, since operator awareness concerning the

-

4

potential for incorrect readings was high.

I

On February 3,1997, the inspector observed the use of the new method for measuring

j

tank oillevel. The measuring stick was easier to read, and the bottom of the tank did not

j

need to be found. Overall the inspector concluded that the new method should be better,

!

- but adverse weather or poor lighting could still make reading the stick more difficult.

.

Operations management indicated that they plan to address these problems in the future.

!

C.

Conclusions

)

Operations management aggressively pursued an improved method for reading the storage

!

tank oil level, in order to make it easier for the operators, considering the current potential

!

for adverse weather or lighting. However, the inspector questioned the adequacy of the

{

interim corrective actions because they did not change the currently vulnerable practices,-

j

or specifically address the root cause and the contributing factors,

i

j

The inspectors concluded that the D14 EDG was inoperable for approximately two months

and that the appropriate actions were not taken as required by technical specifications.

a

!'

With one EDG inoperable, TS require that the remaining A.C. sources be demonstrated

operable, by performance of surveillance requirements. At least four instances were

,

j

identified where operators had an opportunity to identify the errors. Additionally,

operations management was aware of the difficulties in obtaining a consistent, reliable

l

measurement, at least since 1992, and adequate corrective actions were not taken.

'

l

Failure to take the actions required by Technical Specification 3.8.1.1 is a violation of

!

technical specifications. No response to this violation is necessary, since corrective

l

actions were reviewed and found adequate. (VIO 352/9610 01)

i

03

Operations Procedures and Documentation

)

03.1

Primary Containment Isolation Valves Found Eneraized - Unit 2

l

j

a.

Insoection Scope (71707)

!

On December 16, during the Unit 2 startup with the reactor operating at 24 percent

power, the shift manager identified that two primary containment isolation valves (PCIV),

~

required to be de-energized per General Plant Procedure (GP) 2, Normal Plant Startup, and

j

Technical Specifications (TS), were energized. He immediately had the breakers locked

j

open. _The valves are required to be de energized prior to exceeding 600 psig when the

i

reactor is critical, which occurred on December 13. The inspector independently reviewed

i

,

i

.

m'

+ , - - , -

,,,vv--.-,,<

ww

,v

w.-.,,---e,

-

r

..m

- ,

--,

w.--

.

- - - . . . - - ~ = --.

. . -

1.---

- 4

---e.

__

. . -

.

_ _ _ . _

__

_ _ . . . _ _ _

_ _ _ _

i

1

-

9

the event, procedures, applicable sections of the Updated Final Safety Analysis Report

(UFSAR), and discussed the event with key personnel.

b.

Observations and Findinas

l

The inspector determined the following sequence of events occurred prior to the event.

i

The feedwater system was partially drained, during the Unit 2 maintenance outage, to

I

allow work on the reactor water clean-up (RWCU) return to feedwater check valves.

.

Operators opened HV-041-209A and B, Reactor Feedwater Startup Flushing PCIVs per

system procedure SOS.4.A, Draining the Condonsate and Feedwater Systems. After

completing the work, the condensate and feedwater systems were filled, vented and

started in short path recirculation. The operators closed the PCIVs during system filling

j

and venting, although procedure SOS.3.A, Filling and Venting Condenser Hotwell;

!

Condensate and Feedwater Systems, did not direct the two PCIVs to be closed. During

i

the preparations for the Unit 2 startup, the control room supervisor (CRS) improperly

signed as' completed the GP-2 procedure step that ensured the PCIVs were closed with

their breakers locked open.

The inspector independently determined that several operator performance and procedure

adherence problems occurred, and that some procedure weaknesses existed.

e

Procedure SOS.4.A directed the operators to unlock and close the breakers for the

PCIVs. The clearance used to drain the feedwater system contained a note stating

that all valves moved in procedure SOS.4.A would be restored in procedure

SOS.3.A. -The inspector verified that the PCIVs were not closed during SOS.3.A

and the procedure does not cause the restoration of the PCIVs to their original

condition. in fact, the only procedure to direct closing and locking open the

breakers for the PCIVs was GP-2. The operators closed these valves without

procedural guidance during the system fill and vent procedure, SO5.3.A.

l

The PCIVs are administratively controlled valves under the locked valve program, A-

l

C-008, and are required to be logged in the Locked Valve Log in the control room if

the valves are unlocked and manipulated. This manipulation, however, was not

l

recorded in the Locked Valve Log.

An independent verification of locked valves that have been manipulated is required

e

per A-C-008 and Operations Manual (OM)-C-11.1, independent Verification, during

component restoration. This action also was not performed.

A-C-008 stated that if locked valves are manipulated by a clearance (provides its

own restoration and independent verification steps), then a Locked Valve Log entry

is not required. This presented a confusion factor to the operators that contributed

!

to the failure to use the Locked Valve Log. A clearance was used but the

restoration was inappropriately referred to procedure 50 5.4.A, which had neither

restoration nor independent verification steps.

.-.

.

.-.

.

!

10

e

The CRS improperly completed the step in GP-2 without positively identifying the

i

valves and ensuring that the PCIV's breakers were opened. Specifically, the CRS

looked across the back control panel to the vicinity of the valves on the front

control panel, saw two valves de-energized and assumed them to be the ones in

question. The two valves he saw were actually the feedwater maintenance

isolation valves (HV-041-F011 A and B) which are also de-energized. The inspector

determined that poor operator practices and lack of self-check as prescribe in A-C-

079, Procedure Adherence and Use, were demonstrated in the performance of this

step.

l

1

The inspector determined that the operators did not comply with the TS requirement. The

two feedwater valves (HV-041-209A and B) are outboard primary containment isolation

valves that isolate the feedwater long-path recirculation header to the main condenser.

They are required in TS Table 3.6.3-1, Note 32, to be " sealed closed" whenever the

reactor is critical and above a reactor pressure of 600 psig. This is done to protect the low

pressure piping from backflow from high pressure systems required for reactor vessel

makeup. The applicable sections of the UFSAR commit to the Standard Review Plan (SRP)

6.2.4, Containment Isciation System, Section ll.6.F definition of " sealed closed," which is

a barrier used in place of an automatic isolation valve, administratively controlled, by

preventing power from being supplied to the valva operator. The inspector determined that

the two valves were closed when reactor pressure exceeded 600 psig, but were not sealed

as required and therefore, wera inoperable. This is a violation of TS 3.6.3.a (VIO 353/96-

10-02).

Management further determined that this condition was not in compliance with the Facility

Operating License (FOL). The Fire Protection Report, Table 9A-12, Valves That Serve as

Interfaces Between Low Pressure Piping and the Reactor Coolant Pressure Boundary, in the

UFSAR, requires that the circuit breakers for these two valves be locked open at the motor

control centers prior to exceeding 600 psig. This is a Fire Safe Shutdown concern to

prevent the spurious openirig of the upstream and downstream valves together as a result

of fire-caused damage resulting in exposing low pressure systems to reactor pressure.

Management identified that failing to lock open the valve breakers violated FOL condition

2.C.3., which required a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> NRC notification that was made on December 16, when

the unit was brought into compliance.

Procedure GP-2 is the administrative control established to ensure compliance with the

above requirement. Steps 3.1.32.3 and 4 of GP-2 direct the operator to ensure that the

two valves are closed, and that the associated breakers are locked opened prior to

exceeding 600 psig. The Procedure Writer's Guide, A-C-001, defines " ensure" as making

sure the expected action occurs by observation or taking the necessary action. Prior to the

steps, a Note emphasizes that the following actions are to be performed prior to exceeding

600 psig. The inspector identified two inadequacies with the procedure.

!

l

e

The Note indicated that the valves should be locked closed, but did not emphasize

the breakers being locked open. The UFSAR section referenced in the Note

commits the valves to be sealed closed.

l

l

,

l

l

l

l

l

11

l

l

The procedure steps were poorly human factored. Each step contained two

operator actions, close the valve and lock open the breaker, with only one sign-off.

The Procedure Writers Guide, A-C-001, limits the operator actions to one per step.

l

The inspector determined that the valves were not identified sooner, in part because of the

lack of an operator aid. All other valve operators required to be de-energized as listed in

i

Table 9A-12 were marked on the control panel with an operator aid signifying that they are

l

de-energized for Fire Safe Shutdown purposes; however, the two feedwater valves had no

operator aid associated with them. The valves remained undetected through at least five

shift turnovers.

1

The inspector observed in the field that the breakers on both units were opened and

locked. Further, other valve operators required to be de-energized as listed in Table 9A-12

were verified on both units. The inspector noted that these other valves were marked on

the control panel with an operator aid signifying that they are de-energized for Safe Fire

Shutdown purposes.

The inspector noted that the operations log entry, made by the unit RO upon discovery of

the event, stated simply that the feeds to the PCIV motor operators were de-energized.

Neither the shift manager nor CRS made any entry or comment as to the non-conformance,

j

significance, nor procedural adherence or notifications that were required.

PECO implemented a performance enhancement process (PEP) investigation into the

causes of the event and determined:

)

The operator signing off the GP-2 step did not use good self-check behaviors.

The restoration process for condensate and feedwater coming out of the outage

was less than adequate, including the clearance and procedures.

l

The use of the Locked Valve log was less than adequate.

Immediate corrective action included operations management verifying that all GP-2 steps

were completed correctly by another CRS and that the breakers were locked open.

Further, other locked valves and Fire Safe Shutdown valves were verified to be in the

correct position. Long term corrective actions include:

i

'

improving self-check methods

e

labeling the PCIVs to indicate they are normally de-energized (black dots have been

installed)

l

l

revising GP-2 to make two procedural steps to close the valve and lock open the

breaker. Also, revising the feedwater fill and vent procedure, SOS.3.A to include

assuring the PCIVs are closed and de-energized.

training operators and communicating management expectations to assure operators

understand the use of the Locked Valve Log

i

- - -

.

- - - - . _ - _

- - - .

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

---

,

,

12

e

' training clearance writers to assure that the restoration sequence of a clearance is

properly and accurately coupled with the system operating procedure

l

c.

Cc,nclusion

l

The inspector concluded that several operator performance and procedure adherence

problems occurred that contributed to the inadequate control of these PCIVs. Procedure

weaknesses also affected the defense-in-depth controls. The two PCIVs were inoperable

between the time when the reactor exceeded 600 psig on December 13 until the time

l

when the breakers for the motor operators were de-energized on December 16. Because

i

the PCIVs were not properly sealed closed, the TS action statement requiring that the

l

penetration be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in Hot shutdown in the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and

l

cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was exceeded. Additionally, the

l

requirements for Fire Safe Shutdown, as stated in the UFSAR Table 9A-12, were not met.

Management's evaluation identified the causes of the event and has implemented

corrective actions to address recurrence of the event. A response to this violation is not

required.

l

07

Quality Assurance in Operations

07.1 Problem Identification and Corrective Action Imolementation (40500)

l

a.

Insoection Swoe

The NRC conducted a comprehensive assessment of Limerick corrective action processes

I

in 1995, and determined that these processes generally were effective in identifying and

coTecting adverse conditions and safety concerns (NRC Inspection Report 50-352,

353/95-80). The purpose of the present inspection was to validate the continued

effectiveness of these processes through review of plant operating and inspection history,

l

and independent verification of the resolution of selected adverse conditions. Program

changes for the performance enhancement and nonconformance processes were verified,

l

as well as, actions to resolve weaknesses detailed in the initial NRC inspection. PECO self

assessment and independent oversight activities were evaluated by comparing NRC

findings with their assessment reports.

Performance Enhancement Proaram Review

l

b.

Observation and Findinas

i

l

The inspectors reviewed procedure LR-C-10, Performance Enhancement Program (PEP),

j

Rev. 5, comparing it with the procedure revision (Rev. 3) that was effective when the

'

1995 Problem identification and Resolution inspection was performed. The inspector

independently reviewed several PEPS and determined that they were of high quality. The

l

inspectors reviewed the threshold of entering issues into the PEP process and the age of

l

outstanding corrective actions, and also discussed the program with appropriate plant

personnel.

!

4

- _

___

.

__

_

_

_

. _ _

_

.

.

1

[

13

The PEP process remains essentially as described in NRC Inspection Report 95-80, except

for the addition of several enhancements and clarifications. Procedure LR-C-6,

Reportability, and the use of the Reportability Reference Manual have been incorporated

into LR-C-10 to reduce redundancy and improve the efficiency of event review. A section

implementing a corrective action effectiveness review was also added. Other clarifications

included guidance for initiating a PEP if items, events, or issues covered by other defined

programs were significant.

The inspectors determined that, in general, the appropriate issues are being identified and

entered into the PEP process within the time expected by plant management. Adequate

!

guidance for identifying Level 1 and 2 issues exists in procedure LR-C-10-03, Examples of

Issues and Their Significance. Further, each organization developed a PEP Threshold

Agreement that specifies clear expectations within each organization to identify Level 3

l

conditions that are adverse to quality. The inspectors determined that these agreements

were a helpful tool to establish useful criteria for identifying issues.

The inspectors noted, however, that plant management involvement is required to ensure

,

that many issues are captured in the PEP process. Several equipment related problems

l

occurred during the inspection that did not get entered into the PEP system for several

l

days, at which time plant management directed that a PEP be initiated for the issue. The

l

inspectors determined that the shitt manager and other staff personnel do not consider

equipment related problems to be PEP issues. Further, the staff does not question if the

broader issue presents a condition that is adverse to quality. Therefore, equipment related

problems are entered into the PEP process when management determines the need to

generate a PEP after further review of the problem.

The inspectors determined that a programmatic inconsistency could be contributing to this

observation. Some processes such as the Control of Nonconformances have a required

management review to debrmine if a condition adverse to quality exists and, if so, initiate

a PEP. Other processes, such ar .quipment Trouble Tags and Corrective Maintenance

r

Action Requests focus on operability, reportability, and repair, but do not require a similar

causal factor screening. As a result, some recurrent or significant equipment problems are

not entered into the PEP process until plant management takes the initiative to stimulate

!

the normal process. The inspectors discussed this point with site management who stated

l

that some initiatives may be necessary to move the threshold awareness down to the

i

worker level.

The Experience Assessment Group initiated the corrective action effectiveness review

'

process in late 1995. The inspectors noted that the corrective action effectiveness

reviews performed were lacking in timeliness and level of challenge. However, the

inspectors recognized that this issue had previously been identified in an in-house self-

assessment and other third party assessments. Appropriate improvements are being

implemented.

l

The inspectors determined that generally, all dispositions of the PEPS reviewed including

some issues that were reportable and required submittal of an licensee event report (LER),

were acceptable. One minor exception concerned a main control room temperature control

,

issue that was identified in LER 1-96-006. This issue was an operator challenge, identified

. _

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

.

l

l

'

!

14

i

i

!

Jn the Operator Challenge program but was not dealt with in a PEP. The Operator

L

Challenge program was not aggressive enough to address the issue in a timely manner to

l

prevent the recurrent issues raised by LER 1-96-006.

)

,

l

Overall, the PEP process is identifying problems, assessing them for corrective actions, and

implementing those actions to prevent recurrence. The program has a broad base, is

'

self-critical, and the thresholds !,eing achieved are appropriate. Plant management

involvement, however, is sequired to maintain the current level of issue identification, and'

some initiatives may be necessary to move the threshold awareness down to the worker

j

levelin the organization. The corrective action effectiveness reviews were frequently not

<

j

timely or thorough,

l

Nonconformance Reportina Proaram

The inspectors reviewed procedure A-C-901, Control of Nonconformances, Rev. 7,

comparing it with the procedure revision (Rev. 5) that was effective when the 1995

Problem Identification and Resolution inspection was performed. The inspector

independently reviewed several nonconformance reports (NCRs) and determined that they

had been appropriately dispositioned. The inspectors reviewed the threshold of the

process, the adequacy of operability and disposition assessments, and the backlog of

outstanding corrective actions.

The NCR process remains essentially as described in NRC Inspection Report 95-80, with

one exception. Revision 7 to the procedure involved a major rewrite of the procedure to

clarify and simplify the specified process. The inspector found that the required process-

remained intact, and the goals of the revision had been satisfactorily achieved.

l

The NCR process change involved the removal of the Nuclear Quality Assurance

Department from the in-line review of NCRs. Implementation of this change in the Quality

Assurance Program began during the prior inspection on January 17,1995. PECO

implemented a comprehensive transition plan including concurrent line and Nuclear Quality

Assurance (NOA) reviews of NCRs for a month, followed by a controlled and monitored

l

phase out of direct NQA involvement. NRC review of the transition documentation

(

indicated that the assessments were critical and effective in holding final transition

approval until acceptable line organization performance was achieved on September 28,

1995. The inspector observed that since the conclusion of the transition process, few

l

NCR dispositions had been surveilled by the NQA organization. This situation provided a

!

weak historical oasis for the completion of the NQA audit of nonconformance processes

required to be completed in 1997. NQA management noted that this situation had been

identified internally, and provided documentation of plans to complete the necessary

surveillance history in support of the scheduled audit.

The inspector confirmed that the sample of NCRs reviewed during this inspection were

appropriately dispositioned. The NCR process continued to be an effective program for

identification and resolution of design and equipment problems,

i

(

l

i

_

. . - .

_

.

, _. _

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

_ _ - _ _

.

.

15

Response to Previousiv identified Proaram Weaknesses

NRC Inspection 50-352,353/95-80 identified corrective action program weaknesses

l

related to some examples where interim or final corrective actions were not timely or

effective in preventing recurre.nt problems. Also, some station personnel were not familiar

-

with aspects of the employee concerns process. The inspectors verified the corrective

i

actions and procedural enhancements implemented to address these potential

vulnerabilities identified during the last inspection.

Plant management and the NQA Department have implemented measures to raise plant

l

personnel's awareness concerning the Employee Concerns Program. Program posters are

displayed throughout the plant and are reissued every six months. General employee

training addresses the program to ensure all employees are introduced to and made aware

of the many diverse methods of raising concerns to the appropriate venue, including the

7

l

NRC. Further, notices are published in the site newsletter, issued at most site access

'

points. To maintain cognizance of the effectiveness of their efforts to stimulate the

process, managers and NQA personnel routinely poli employees reganiMg their awareness

l

and use of the program. While some empoyets do not retain detailed know! edge of the

)

l

process, the inspectors netad that the program b being utilized, and detarmined that PECO

management has taken appropriate steps to raise employee awareness.

.

The NRC had previously identified that station managers had frequently directed that

assessments be conducted for deficient areas or recurring errors. These assessments and

l

the resultant recommendations, however, were not conducted within the PEP process.

During this inspection, the inspectors verified that trending assessments are being captured

!

and tracked in the PEP system. The inspectors reviewed two recent trending review PEPS

I

and noted that the assessments with their recommendations were tracked in the PEP

-

- system to satisfactory completion. The inspectors also noted that about 15 other trend

PEPS were documented in 1996.

-

l

Regarding the timeliness of corrective actions, the age of backlogged action evaluations

(A/E) are actively tracked. A/Es are used to track specific corrective actions resulting from

PEP issue evaluations. Due dates are negotiated on a case by-case basis, prioritized on the

significance of the issue. A performance indicator depicting the history profile of A/Es is

maintained by the Experience Assessment Coordinator and issued every two weeks to

plant management. Supporting data is sent to the responsible line organization to ensure

that each corrective action is being implemented on a schedule commensurate with the

significance of the associated issue. The inspectors noted that this method of tracking has

i

l

decreased the number of older A/Es.

]

Finally, as detailed in Section 7.1.2.1 of this report, PECO implemented corrective action

effectiveness reviews (CAERs) to validate that prescribed actions have been successful.

The inspectors found examples of shallow or late implementation of these reviews that

,

contributed to recurrent problems. Recent PECO assessments have also emphasized the

need for improved CAERs. In addition to more management attention to this area, the

Events Assessment Department has begun PEP critique sessions and a mentoring process

to further enhance the quality of the corrective action process.

i

i

l

!

.

-

.

-

.

.

.

-

__

.

._

'

1

,

16

The issues identified in the previous corrective action inspection were adequately

addressed and verified during this inspection. PECO management's corrective actions

addressing the employee concerns program awareness were appropriate. Management

improved the formality and tracking of recurrent problems. The corrective action

effectiveness reviews need to be more challenging and timely. Continued enhancement in

this latter area has also been identified via station self-assessment.

Indeoendent Oversiaht

l

The inspectors reviewed selected reports of independent oversight activities regarding

Limerick Station, to determine whether program weaknesses and performance trends had

been self-identified and tracked to resolution. All of the discrepancies and weaknesses

identified by the NRC were captured by self-assessment, NQA or third party activities, and

planned for resolution with appropriate management support and priority.

l

NRC assessment of Limerick performance in early 1996 indicated a decline in Operations

I

performance (NRC letter dated June 14,1996), and questioned whether oversight

activities had been effective in preventing or promptly resolving these concerns. During

this inspection, NRC reviewed the records of NQA and Nuclear Review Board (NRB)

activities, and found that these adverse trends were noted by NQA in their March - April

1996 report to the NRB. The NRB conducted routine and follow-up discussions regarding

the trend and management's response to correct the problems. The inspectors noted that

the NRB activities appeared to be focused on actions to address the noted problems, with

less attention on the underlying causes for the decline, and the Quality program's

effectiveness in preventing adverse trends.

.

The inspector generally identified that the NRB process provides broad, critical assessment

l

of site and corporate activities. However, the consistency in which concerns were marked

l

for formal follow-up varied, and the clarity of the Board's expectations for the line

l

organization's response to certain open issues could be improved. An example was the

NRB's treatment of computer software quality concerns, which required severaliterations

to achieve acceptable response. The NRB Chairman noted that NRB conducts routine self-

l

assessment activities which have made similar observations. The inspector concluded that

l

independent oversight activities are fulfilling the regulatory requirements and that

continuing improvements are being pursued.

Finally, the inspectors noted that PECO uses several initiatives to help focus on problem

areas and assess plant performance including the Focus on Excellence and Event Free

l

Operations processes. These initiatives are not proceduralized processes, rather

!

management tools for aiding the station to be effective in reducing plant challenges. The

inspectors observed that these programs may be widely credited at the site as solutions to

formally documented causal analyses. The inspectors questioned whether the level of

quality would be maintained if these programs were reduced or eliminated. The plant

manager acknowledged this concern and indicated his intent to revisit the continued need

'

and formality of these tools.

l

17

b.

Conclusion

Limerick's problem identification and resolution programs were found to be improved and

effective. They have appropriate thresholds, are sufficiently critical, and track actions to

completion. There is strong management and oversight support through participative

supervision, resource commitment, and high expectations. Corrective action backlogs are

managed to an acceptable level. Station self-assessment reviews were very effective,

having recognized and acted upon all the discrepancies identified by the inspectors. The

corrective action effectiveness reviews need to be more timely and critical, to assure

interim recurrences are prevented.

07.2 Self-Assessment Activities (71707)

During the inspection period,the inspectors reviewed or attended multiple self-assessment

activities, including:

various Plant Operational Review Committee (PORC) meeting and meeting minutes;

e

various quality verification (QV) and independent safety engineering group (ISEG)

reports.

The PORC reviewed several activities related to safe station operation. The members of

PORC actively participated in the meeting with open discussions on the plant issues while

maintaining a focus on safety. The inspector concluded that the self-assessment activities

were effective.

08

Miscellaneous Operations issues (90712, 92700)

08.1 (Closed) LER, 1-96-022, D14 Emeraency Diesel Generator Inocerable Due to Low

Fuel Oil in Storaae Tank

This event is reviewed in section O2.2 of this inspection report. The LER met the

requirements of 10 CFR 50.73, and the inspectors had no further questions regarding the

event.

08.2 (Closed) LER 2-96-008, Two Breakers Not Locked Ooen Contrary to Fire Protection

Proaram Analysis

This event is reviewed in section O3.1 of this inspection report. The LER met the

requirements of 10 CFR 50.73, and the inspectors had no further questions regarding the

event.

08.3 (Closed) LER 2-96-009, Unit 2 SCRAM, a Reactor Protection System Actuation, Due

to a Failure of a Ball Joint that Connects the Recirculation Pumo Motor Generator

Set Scoon Tube to the Tube Positioner

This event is described in this inspection report in the Summary of Plant Status. The LER

met the requirements of 10 CFR 50.73, and the inspectors had no further questions

j

regarding the event.

18

11. Maintenance

M1

Conduct of Maintenance

M 1.1 General Comments

a.

Insoection Scope (62707)

The inspectors observed all or portions of the following work activities:

e

D13 EDG 18 month inspection

e

2A main condenser expansion joint replacement - Unit 2

New fuel receipt inspection and channeling - Unit 2

e

Repair of HPCI speed sensor - Unit 1

'

e

Stator cooling pump mechanical seal replacement - Unit 1

e

Repack HPCI steam line drain pot drain trap bypass valve - Unit 1

i

'

e

Repair HPCI oil line flange leak - Unit 2

e

D14 EDG generator bearing temperature element replacement

b.

Observations and Findinas

Nuclear maintenance division (NMD) and plant maintenance personnel performed the

replacement of the 2A main condenser expansion joint well. The joint is situated such that

it can only be replaced from inside the condenser. During the four day outage which

began December 18, NMD personnel erected scaffolding inside the main condenser and

replaced the expansion joint in a controlled and professional ma>mer. The inspector noted

that proper foreign material exclusion controls were in place and utilized.

NMD personnel performed the handling, inspection, channeling, and placing of the new fuel

into the Unit 2 fuel pool in a professional and well coordinated manner. The inspector's

observations of new fuel handling on the refuel floor, demonstrated that the NMD crew

and the site radiation protection personnel functioned well. The activity was performed

completely event-free and was completed on January 3.

The 1 A stator cooling pump developed a one pint per minute leak from the mechanical seal

on January 8. Maintenance technicians replaced the seal and returned the pump to service

on January 10. The inspector noted that the planning and implementation of the corrective

maintenance task was effectively resolved.

M1.2 General Comments on Surveillance Activities (61726)

The inspectors observed selected surveillance tests to determine whether t pproved

procedures were used, details were adequate, test instrumentation was properly calibrated

and used, technical specifications were satisfied, testing was performed by knowledgeable

personnel, and test results satisfied acceptance criteria or were properly dispositioned.

.

.

-

.

-

. ..

..

- - . _

-

..

.

'

.

1

19

.

The inspectors observed portions of the following surveillance activities:

D22 EDG monthly - fast start surveillance

D12 EDG monthly - slow start surveillance

e

D23 EDG monthly - fast start surveillance

.

Observed surveillance tests were conducted well using approved procedures, and were

completed with satisfactory results. Communications between the various work and

support groups were good, and supervisor oversight was good.

'

M2

Maintenance and Material Condition of Facilities and Equipment

M 2.1 Insoection/ Maintenance of D13 Emeraency Diesel Generator (EDG)

4

a.

Insoection Scoce (62707#

,

The 18 month inspection and maintennoce outage for the D13 EDG began on December

16. The inspectors reviewed and obser red portions of the outage activities,

b.

Observations cd Tbdings

Maintenance personrul ,nerformed inspections, testing and general maintenance on the D13

EDG. The inspectors observed that the maintenance work was well controlled and

=

conducted in accordance with procedures.

During the inspection, technicians found fragments of a piston compression ring in the

exhaust debris catcher, and the No. 2 lower piston was scored in several places. The

compression ring closest to the piston crown had broken causing the damage. The

j

maintenance technicians replaced the piston and determined that the cylinder wall was not

damaged. The ring fragments were sent to a metallurgical laboratory for failure analysis.

Following the reassembly of the EDG, plant personnel performed an extended run-in test of

the EDG, and a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run. The operators declared the diesel operable on

December 24 after satisfactorily completing the endurance run.

.

c.

Conclusions

2

The inspectors concluded that the 18 month inspection and maintenance of the D13 EDG

was performed well. The follow-up testing and repairs were effectively controlled and

1

included a significant level of engineering support. Failure analysis of the broken piston

ring remains pending.

-

- _ -

. -

._ .-

- - _

.

.

--

. - _ .

--

.-

,

'

l

r

20

l

M8

Miscellaneous Maintenance issues (90712)

M8.1 (Closed) LER 2 96-006, inadvertent Start of the D21 Emeraency Diesel Generator

l

On December 2,1996, an l&C technician inadvertently bumped a test switch box, during

a core spray system response time test; the test switch box was installed to prevent the

start of the EDG when a loss of coolant accident (LOCA) signal was initiated. Due to a set

of contacts with a defective solder joint, the contacts open when bumped; this caused the

LOCA signal to start the EDG, The test was terminated, the EDG was secured, and the

LOCA signal was reset. The EDG started as designed, and no other system was

!

challenged by the event. The test switch box was repaired, and inspection of the

remaining test switch boxes revealed no problems. Additionally, a program will be

developed to ensure that the test switch boxes are routinely examined and tested; other

l&C test equipment was found to be tested at established frequencies or testing is

unnecessary. The LER met the requirements of 10 CFR 50.73, and the inspectors had no

further questions regarding the event.

!

I

Ill. Enaineerina

E2

Engineering Support of Facilities and Equipment

!

E2.1

Enaineerina Evaluation of the Unit 2 Exoansion Joint Failure

a.

Inspection Scope (375511

The inspector reviewed and discussed with the engineering staff, the evaluation made to

replace the main condenser expansion joint.

b.

Observations and Findinas

PECO engineers determined that age was the primary cause of the failure of the Unit 2

main condenser expansion joint. The expansion joint is a nylon re-enforced rubber seal

that provides a flexible seal between the main condenser and low pressure turbine. Ten

years is the typical life expectancy for the expansion joint material. Engineering had

planned to replace the expansion joint during the upcoming 2R04 refueling outage.

The engineering staff recommended to management that the expansion joint be replaced

immediately, rather than wait until the refueling outage. The engineers evaluating the

expansion joint prior to the unit shutdown determined that the material had been

deteriorating for some time before it ripped. By using a boroscope, the engineering staff

determined that the size of the rip was approximately 18 inches. The condition of the

rubber would continue to degrade with the combined heat and water acting upon it.

Although the temporary repair decreased air inleakage to the condenser, the engineers

I

were not able predict when a failure would occur. Further study of industry events

l

involving failed expansion joints, indicated that failures were sudden, without warning, and

involved a rapid loss of vacuum.

,

,

,

--

.

21

c.

Conclusion

The engineering staff effectively supported the safe operation of the unit. A thorough

review of the condenser to turbine expansion joint condition and possible failure

mechanism resulted in a timely determination of the need for prompt replacement.

E8

Miscellaneous Engineering issues (90712,90713,92903,92700)

E8.1

(Closed) URI 352/353/96-09-02. Dearaded HPCI Soeed Sensor. and (Closed) LER 1-

96-018. Revision 1. Loose Speed Sianal Cable Connector Renders the Sinale Train

Hiah Pressure Coolant Iniection System inocerable

This item remained unresolved pending information obtained after the Unit 1 HPCI speed

sensor connection was replaced and inspected for indicadens of damage or problems. The

inspector was concerned that inadequate maintenance may mve caused the speed sensor

connection to be broken, resulting in a lost speed signal, and t*ie subsequent declaring of

the HPCI system inoperable. The inspector reviewed the plant investigation into the event,

j

attended the PORC review meeting of the investigation, discussed the root cause and

corrective actions with plant personnel, and reviewed the LER.

The inspector concluded that the investigation and subsequent PORC review were mak.

Specifically, the investigation concluded that the most probable root cause was that the

i

connection became degraded when a technician overtightened the connector during

reassembly in February 1996. This conclusion was reached without interviewing the

technician who worked on the connection, and without testing a new connection to verify

that the failure mode was consistent with overtightening the connection. The PORC

accepted the most probable root cause without further questioning. After the plant

manager became aware of the weak PORC review, he challenged the PORC chairman to

review the event again; the PORC chairman subsequently remanded the issue, for a future

j

PORC review.

Plant personnel continued the investigation, by destructively testing a new connection and

j

interviewing the technician who performed the work in February 1996. This resulted in

additional information and the revision to the LER. The failure mode was verified by

overtightening a new connection until it broke. Interviews with the technician who last

tightened the connection in February 1996, indicated that no difficulties were noticed

when reconnecting the speed sensor connection, and tools were not used to tighten the

connection. Management concluded that the exact cause of the improper connection

could not be determined, but i: was probably due to a misalignment of the connector as it

was tightened.

Corrective actions included replacing the connector on January 2,1997, revising the

appropriate procedures to include a caution statement regarding proper assembly of the

connection, and personnel who work with these style and similar connectors were briefed

about this event and proper connector manipulation techniques. Additionally, the speed

sensor connection will be evaluated for a possible design change.

.

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

-

.

.

. _ _ _ . . _ _ _

__

.

.

_ _ _

.

-

j

!

1

!

22

1

i

The Nuclear Quality Assurance Plan MI 5.1, and 10 CFR 50 Appendix B, criterion V,

require in part that maintenance activities affecting quality shall be prescribed by

documented instruction of a type appropriate to the circumstances, and instructions shall

4

include appropriate quantitative or qualitative acceptance criteria for determining that the

j

activities have been adequately and satisfactorily accomplished. In February 1996,

{

maintenance was conducted on the Unit 1 HPCI speed sensor connection inadequately,

resulting in an inoperable HPCI system, as identified on September 25,1996. This

e

licensee-identified and corrected violation is being treated as a Non-Cited Violation,

i

consistent with Section Vll.B.1 of the NRC Enforcement Policy.

l

E8.2 Special Report, Valid Emeraency Diesel Generator Test Failure

1

i

!

On January 1,1997, during performance of the D21 EDG monthly surveillance test, after

starting, the EDG's speed increased more than expected to a value corresponding to the

,

4

mechanical governor high speed stop. This indicated that the electronic governor was

potentially malfunctioning. After the EDG was shut down, an inspection of the electronic

i

governor identified a loose wire. All wires on the terminal block we'e tightened, the other

!

EDGs were satisfactorily tested as required by technical specifications (TSs), and terminal

connection inspections were initiated on the other EDGs. Additionally, other plant systems

which utilize governors will be evaluated for similar conditions. The Special Report met the

f

requirements of TS 4.8.1.1.3, and the inspectors had no further questions regarding the

event.

i

l

E8.3 (Closed) LER 1-96-020, Primary Containment Isolation Valves inadvertentiv Closed

Due to Personnel Error Durina Manioulation of Breaker Switches in Local Distribution

Panel

l

On December 5,1996, a maintenance technician inadvertently bumped open a breaker -

i

switch adjacent to the switch he was operating, causing two primary containment isolation

i

valves to close. The technician immediately reclosed the breaker switch, thereby restoring

power to the valves. The consequences for this event were minimal since the valves were

j

restored quickly; the valves were associated with the drywell radiation monitoring

}

containment leak detector, and no radioactive material was released during the brief period

i

it was isolated. The technician was counseled, and other station personnel were informed

l

of the event, appropriate self-check practices and the best technique for manipulating this

j

type of breaker switch. The LER met the requirements of 10 CFR 50.73, and the

inspectors had no further questions regarding the event.

E8.4 (Closed) URI 50-352, 353/96-09-01. Accarent non-comoliance with fire safe

j

shutdown license condition, and LER 1-96-021, Failure to Provide Sufficient Repair

l

Actions Needed to Achieve Cold Shutdown for Fire Safe Shutdown Capability

i

This issue involved an instance where engineering personnel identified a condition where

the primary containment instrument gas (PCIG) supply to the safety relief valves (SRVs),

i

required to operate during certain conditions, might not meet its intended function which is

due to previously unaccounted for system leakage. The subject LER was issued due to

i

this being a violation of a License Condition (2.C.(3)), which requires the implementation

and maintenance of all provisions of the approved Fire Protection Program as described in

1

1

_.-

.

_

-

.

8

.

23

the Updatad Final Safety Analysis Report. In the event of a significant fire in the main

control rolm, the auxiliary equipment room, or the cable spreading rooms, operators would

need to :iout down both units from the Remote Shutdown Panels. Three SRVs would need

to bo operated t) assist in achieving cold shutdown. The shutdown analysis relies on the

PCiG system to eperate the SRVs for up to six hours; however, a review of actual PClG

system operation revealed that the system may only remain available for up to one hour.

This violation of the Facility Operating License Condition is an apparent violation.

(eel 352/353/9610-03)

Engineering personnel concluded that sufficient plant equipment would have remained

available to maintain the plant in a hot shutdown condition until necessary repairs could be

made to achieve cold shutdown. The inspector confirmed that the safety related functions

of PCIG and the SRVs were not affected by system leakage concerns.

Corrective actions taken included: an hourly fire watch was immediately implemented; a

protected source of pressurized gas was provided for both units on December 12,1996,

which restored both units to full compliance with the Operating License Condition; and by

December 1,1997, it is expected that a comprehencive review of all of the assumptions

made in the fire safe shutdown analysis, a verificatien of all of the fire safe shutdown

repairs, and a review of all the fire safe shutdown systems will be completed to verify

physical capability to perform as required.

E8.5 (Closed) LER 2-96-007. Manual Reactor Scram Resultino From a Leak in the Main

,

Turbine Electro-Hydraulic Control System Due to the Failure of a Pressure Switch

Sucoort Bracket and Tubino

This event was reviewed in NRC Integrated Inspection Report 50-352/96-09, 50-353/96-

09. The LER met the requirements of 10 CFR 50.73, and the inspectors had no further

questions regarding the event.

IV. Plant Support

S1

Conduct of Security and Safeguards Activities

a.

Insoection Scoce (81700)

The inspector reviewed the security program during the period of January 6-10,1997.

Areas inspected included: effectiveness of management control; management support;

'

protected area (PA) detection equipment; alarm stations and communication; testing,

maintenance and compensatory measures; and training and qualification, and control of

vehicles. The purpose of this inspection was to determine whether the security program,

as implemented, met commitments and NRC regulatory requirements,

b.

Observations and Findinos

Management support is ongoing as evidenced by upgrades to the assessment system,

renovations to the personnel processing center to improve flow of personnel during

-- -

.

..-

,

-

-

--

__-.

24

processing, allocation of resources for additional tactical, firearms and emergency medical

technician (EMT) training, and the initiative that established a partnership with local law

enforcement agencies for an improved firearms range. Alarm station operators were

knowledgeable of their duties and responsibilities and security training was being

performed in accordance with the NRC-approved training and qualification (T&Q) plan.

Management controls for identifying, resolving, and preventing programmatic problems

were effective.

The PA detection equipment satisfied the NRC-approved physical security plan (the Plan)

commitments and security equipment testing was being performed as required by the Plan.

Maintenance of security equipment was being performed in a timely manner as evidenced

by minimal compensatory posting associated with non-functioning security equipment.

c.

Conclusions

The inspector determined that the licensee was conducting its security and safeguards

,

activities in a manner that effectively protected public health and safety.

S2

Status of Security Facilities and Equipment

S 2.1

Protected Area Detection Aids

a.

Insoection Scooe (81700)

The inspector conducted a physical inspection of the PA intrusion detection systems (IDS's)

to verify that the systems were functional, effective, and met the licensee's plan

commitments.

.

b.

Observations and Findinas

On January 9,1997, the inspector determined by observation that the IDSs were

functional and effective, and were installed and maintained as described in the Plan. The

inspector also observed performance testing of selected IDS zones on that date,

c.

Conc:nor.

The PA IDSs met the licensee's Plan commitments.

S2.2 Alarm Stations and Communications

a.

losoection Scoce (81700)

Determination whether the Central Alarm Station (CAS) and Secondary Alarm Station

(SAS) are: (1) equipped with appropriate alarm, surveillance and communication

capability, (2) continuously manned by operators, and that (3) the systems are

independent and diverse so that no single act can remove the capability of detecting a

threat and calling for assistance, or otherwise asponding to the threat, as required by NRC

regulations.

25

b.

Observations and Findinas

Observations of CAS and SAS operations verified that the alarm stations were equipped

with the appropriate alarm, surveillance, and communication capabilities. The inspector

determined by observation that the assessment aid upgrade has greatly improved the

assessment capability. Additionally, the licensee has installed an upgraded video capture

program to further enhance the assessment system. Interviews with CAS and SAS

operators found them knowledgeable of their duties and responsibilities. The inspector

also verified through observations and interviews that the CAS and SAS operators were

not required to engage in activities that would interfere with their assessment and

response functions, and that the licensee had exercised communications methods with the

locallaw enforcement agencies as committed to in the Plan.

c.

Conclusion

The alarm stations and communications met the licensee's Plan commitments and NRC

requirements.

S2.3 Testina, Maintenance and Comnensatorv Measures

a.

Inspection Scope (81700)

Determination whether programs were implemented that will ensure the reliability of

security related equipment, including proper installation, testing and maintenance to

replace defective or marginally effective equipment. Additionally, determination that when

security related equipment failed, the compensatory measures put in place were

comparable to the effectiveness of the security system that existed prior to the failure.

b.

Observations and Findinas

Review of testing and maintenance records for security-related equipment confirmed that

the records were on file, and that the licensee was testing and maintaining systems and

equipment as committed to in the Plan. A priority status was assigned to each work

request and repairs were being completed in a timely manner from the time a work

request, necessitating compensatory measures, was generated.

c.

Conclusions

Security equipment repairs were being completed in a timely manner. The use of

compensatory measures was found to be appropriate and minimal.

S5

Security and Safeguards Staff Training and Qualification (T&Q)

a.

Inspection Scope (81700)

Determination whether members of the security organization were trained and qualified to

perform each assigned security related job task or duty in accordance with the NRC-

approved T&Q plan.

- - - .

.

-.

_

-

-

.

26

b.

Observations and Findinas

On January 8,1997, the inspector reviewed the training records for three new officers

that had received initial training during 1996 and three supervisors and three officers that

had received requalification training. Additionally, the inspector interviewed a number of

supervisors and officers to determine if they possessed the requisite knowledge and ability

to carry out their assigned duties.

c.

Conclusions

The inspector determined that training had been conducted in accordance with the T&Q

plan. All training records were complete and all required training had been completed

within the required 12 month time period. Based on the supervisors' and officers'

responses to the inspector's questions, the training provided by the security training staff

was considered effective.

S6

Security Organization and Administration

a.

inspection Scoce (81700)

A review of the level of management support for the physical security program was

conducted.

b.

Observations and Findinas

The inspector reviewed various program enhancements made since the last program

inspection, which was conducted in February 1995, and discussed them with security

management. These enhancements included upgrades to assessment aids, including new

PA tilt and zoom cameras and an updated video capture system, renovations to the

personnel processing center (PPC) to improve personnel flow during outage processing,

additional tactical firearms instructor and EMT training, and an initiative for an improved

firearms range through the establishment of a partnership with severallocallaw

enforcement agencies. Improvements to an existing range will be funded through the

partnership. The licensee will now have a range available near the site. Prior to the

establishment of the partnership, the licensee was renting time at a range that was

approximately an hour away from the site. The proximity of the range to the site will

make firearms training and practice more convenient and efficient.

c.

Conclusions

Management support for the physical security program was determined to be excellent.

_

. - - . . - - -

?

I

i.

'

>

.

27

j

S7

Quality Assurance in Security and Safeguards Activities

l

l

t

57.1 Effectiveness of Manaaement Controls

k

j

a.

Insoection Scope (81700)

i

j

A review was conducted to determine if there were adequate controls for identifying,

i

resolving and preventing programmatic problems.

l

t

1

!

'

]

b.

Observations and Findinas

J

i

i

The inspector determined that there were adequate controls for identifying, resolving, and

{

preventing security program problems. These controls included the performance of the

required annual quality assurance audit, an ongoing self assessment program, an on-shift

T&Q task plan challenge program, and an ongoing security shift supervision oversight.

l

The licensee was also utilizing industry data, such as violations of regulatory requirements

l

identified by the NRC at other facilities, as a criterion for self-assessment.

i

i

c.

Conclusions

4

A review of documentation applicable to the licensee controls, including results, indicated

{

that security performance errors were being minimized and controls were being effectively

j

implemented to identify and resolve potential weaknesses.

ij'

S8

Miscellaneous Security and Safeguards issues (90712,71750)

!

S8.1 (Closed) LER 1-96-014. revision 2. Imorocertv Generatina Safeauard Information

4

This event was reviewed in NRC Combined inspection Report Nos.50-277/96-11, 50-

i

278/96-11, 50-352/96-08, and 50-353/96-08, and resulted in an apparent violation. The

'

LER met the requirements of 10 CFR 50.73, and the inspectors had no further questions

l

regarding the event.

!

{

S8.2 Loss of Control of Master Kevs

!

On January 31,1997, PECO Energy notified the NRC of the discovery that master keys

j

were improperly controlled and in the possession of unauthorized personnel, some of

whom had unescorted access to the Limerick plant. Some of these keys had been

improperly controlled for several years; an investigation was continuing to identify how

many keys were not properly controlled, and to identify what locks the keys would open.

However, it was thought that the keys would allow access to numerous plant areas

including vital areas and locked high radiation areas. The inspectors discussed the event

with station management and verified that appropriate immediate corrective actions were

being implemented. This item is unresolved pending review of further information as to

the extent of the problem and its significance. (URI 352,353/96-10-04)

I

l

!

)

-.

-

.- -

---

..

--.

.

-

- .-.

-

.

.

28

V. Manaaement Meetinas

i

X1

Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on February 3,1997, and on February 5,1997. The plant

,

j

manager acknowledged the findings presented.

l

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

'

!

X2

Review of UFSAR Commitments

A recent discovery of a licensee operating their facility in a manner contrary to the

Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a

special focused review that compares plant practices, procedures and/or parameters to the

UFSAR description. While performing the inspections discussed in this report, the

inspectors reviewed the applicable portions of the UFSAR that related to the areas

inspected. With the exception of the licensee identified discrepancies detailed in Sections

03.1 and E8.4 of this report, the inspectors verified that the UFSAR wording was

consistent with the observed plant practices, procedure and/or parameters.

Since the UFSAR does not specifically include security program requirements, the

inspector compared licensee activities to the NRC-approved physical security plan, which

is the applicable document. While performing the inspection discussed in this report, the

inspector reviewed Section 3.2.2 of the Plan titled, " Vehicle and Cargo Access reviews,

and observations, the inspector determined that vehicles were being searched prior to

entry into the PA and controlled while in the PA as described in the Plan and applicable

procedures.

l

l

/

.

.

INSPECTION PROCEDURES USED

IP 37551:

Onsite Engineering

IP 40500:

Effectiveness of Licensee Controls in identifying, Resolving, and Preventing

Problems

IP 61726:

Surveillance Observation

IP 62707:

Maintenance Observation

IP 71707:

Plant Operations

IP 81700:

Physical Security Program For Power Reactors

IP 90712:

In-office Review of Written Reports

IP 90713:

Review of Periodic and Special Reports

IP 92700:

Onsite Followup of Written Reports of Nonrcutine Events at Power Reactor

Facilities

IP 92902:

Followup - Maintenance

IP 92903:

Followup - Engineering

IP 93702:

Prompt Onsite Response to Events at Operating Power Reactors

ITEMS OPENED, CLOSED, AND DISCUSSED

Ooened

352/96-10-01

VIO

Low EDG fuel oil storage tank level (O2.2)

353/96-10-02

VIO

PCIVs not properly sealed closed (O3.1)

352,353/96-10-03 eel

Fire Safe Shutdown Analysis Error (E8.4)

352,353/96-10-04 URI

Loss of Control of Master Keys (S8.2)

Closed

1-96-014, rev 2

LER

1mproperly Generating Safeguard information (S8.1)

1-96-018, rev 1

LER

Loose Speed Signal Cable Connector Renders the Single Train

High Pressure Coolant Injection System inoperable (E8.1)

1-96-020

LER

Primary Containment isolation Valves inadvertently Closed Due

to Personnel Error During Manipulation of Breaker Switches in

Local Distribution Panel (E8.3)

1-96-021

LER

Failure to Provide Sufficient Repair Actions Needed to Achieve

Cold Shutdown for Fire Safe Shutdown Capability (E8.4)

1-96-022

LER

D14 Emergency Diesel Generator inoperable Due to Low Fuel

Oil in Storage Tank (08.1)

_ -

. . ~ . - .

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

- _ _ . - .

..

_ _ - . . _ .

- . . - -

-

i

.

2-96-006

LER

Inadvertent Start of the D21 Emergency Diesel Generator, an

ESF, During Surveillance Testing. The Cause was Attributed

to the Malfunction of a Test Switch Box (M8.1)

2-96-007

LER

Manual Reactor Scram Resulting From a Leak in the Main

Turbine Electro-Hydraulic Control System Due to the Failure of

a Pressure Switch Support Bracket and Tubing (E8.5)

2-96-008-

LER

Two Breakers Not Locked Open Contrary to Fire Protection

Program Analysis (08.2)

2-96-009

LER

Unit 2 SCRAM, a Reactor Protection System Actuation, Due to

a Failure of a Ball Joint that Connects the Recirculation Pump

Motor Generator Set Scoop Tube to the Tube Positioner (08.3)

352/96-09-02

URI

Degraded HPCI Speed Sensor (E8.1)

,

352,353/96-09-01 URI

Apparent non-compliance with fire safe shutdown license

condition (E8.4)

i

Discussed

None

J

1

l

-

.

. . . .

-

-

-

-

.

.

.- -~ -. -

_~

. _. -

.

- . - _

_

.

4

t

LIST OF ACRONYMS USED

A/E

Action Evaluation

[

CAER

Corrective Action Effectiveness Review

l

CAS

Central Alarm Station

CFR

Code of Federal Regulations

ECCS

Emergency Core Cooling System

EDG

Emergency Diesel Generator

EMT

Emergency Medical Technician

1

EO

equipment operator

i

ESF

Engineered Safety Feature

i

FOL

Facility Operating License

l

FR

Federal Register

GP

General Procedure

HCU

Hydraulic Control Unit

j

HPCI

High Pressure Coolant injection

'

IDS

Intrusion Detection Systems

.

IR

Inspection Report

lSEG

Independent Safety Engineering Group

'

LER

Licensee Event Report

LOCA

Loss of Coolant Accident

MSIV

Main Steam isolation Valves

l

NCR

Nonconformance Report

j

NCV

Non-Cited Violation

'

l

NMD

Nuclear Maintenance Division

I

NRB

Nuclear Review Board

NRC

Nuclear Regulatory Commission

OM

Operation Manual

PA

Protected Area

PEP

Performance Enhancement Program

PCIG

Primary Containment Instrument Gas

PCIV

Primary Containment isolation Valve

PORC

Plant Operations Review Committee

PPC

Personnel Processing Center

psig

pounds per square inch gage

QA

Quality Assurance

QV

Quality Verification

RCIC

Reactor Core Isolation Cooling

RHR

Residual Heat Removal

RWCU

Reactor Water Clean-Up

SAS

Secondary Alarm Station

scfm

standard cubic feet per minute

SRP

Standard Review Plan

SRV

Safety Relief Valve

T&Q

Training and Qualification

TS

Technical Specification

TCV

Temperature Control Valve

l

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved item

l

VIO

Violation

'