ML20132H272

Insp Rept 50-298/96-26 on 961020-1130.Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20132H272
Person / Time
Site:	Cooper
Issue date:	12/26/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20132H232	List: ML20132H227 ML20132H262 ML20132H272
References
50-298-96-26, NUDOCS 9612300035
Download: ML20132H272 (23)

See also: IR 05000298/1996026

Text

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

.

.

ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-298

License No.'. DPR-46

Report No.: 50-298/96-26

Licensee: Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: P.O. Box 98

i Brownville, Nebraska

Dates: October 20 through November 30,1996

Inspectors: Mary Miller, Senior Resident inspector

Chris Skinner, Resident inspector

Approved By: Elmo Collins, Chief, Project Branch C

Division of Reactor Projects

ATTACHMENT: Supplemental Information

l

l

l

l

!

!

4

i

i

!

)-

' 9612300035 961226

'

PDR ADOCK 05000298

G PM

I

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

,

.

I

l

.

EXECUTIVE SUMMARY l

Cooper Nuclear Station

NRC Inspection Report 50-298/96-26

Operations

• Inspectors found several examples of inadequate or nonexistent documentation of

operations information, including an inspector-identified violation with two examples

of failure to document Technical Specifications required common cause failure

evaluations associated with diesel generator failures. Written guidance had not

been provided to the operators, and shift supervisors had an inconsistent

understanding of how to implement this requirement. Additionally, night orders

documentation was not timely.

• Inspectors noted exampft s of operations identification of inadequate work packages

submitted to the control room, indicating higher control room standards for work )

packages as a result of corrective actions to prior problems. In one instance, the

NRC questioned plant conditions to support maintenance and found an ineffective

evaluation of system interdependencies. Control room operators were challenged

by these work packages.

l

• Initial assessment of Operation's immediate response to a fire in the protected area,  ;

and to a separate concern involving slush buildup in circulating water bays due to

lack of the design ice deflector, found that operations performed in an appropriate

manner.

Maintenance

• Maintenance activities were generelly conducted in an appropriate manner with only

minor problems observed. Contradictory administrative procedure guidance

regarding the need to perform surveillance procedures steps in sequence was found.

• A noteworthy strength was identified in that instrument and controls technicians

have achieved a high level of safety focus in problem identification. Continued

improvements in quality and number of problems identified in design, procedures,

and human performance area have been demonstrated.

Enaineerina

• An example of strong problem identification which found that a relief valve in a

sample line was set too high, in that a system valve may be vulnerable to exceeding

design pressure. The licensee addressed isolating the sample line.

Plant Support

• Inspectors found a personnel thermoluminescent dosimeters, which had been lost,

in a pump room.

• Inspectors observed an example of weak contamination control practices.

l

l

_ _

.

.

Report Details

Summary of Plant Status

The plant was maintained at 100 percent power, except for quarterly turbine valve testing,

during which power was reduced to 70 percent. l

.

i

1. Operations

01 Conduct of Operations

01.1 Ice in Circulatina Water intake Bavs (93702_)

a. Insoection Scope (71707)

The inspectors reviewed plant conditions ard licensee response to an occurrence of

ice slush in the circulating water intake bays.

b. Observations and Findinas

On November 26,1996, the licensee noted alarms for high differential pressure l

across intake screens and determined that slush from pad ice on the surface of the

Missouri River had become entrained in the circulating water flow, pulled downward

10 feet below the river's surface, and collected in the circulating water intake.

Although the river temperature was above freezing at 33.5*F, the entrainment of

slush from the surface of the river resulted in high differential pressure across the

surface of the circulating water screens and slush buildup in the circulating water

intake bays. The licensee noted that the safety-related service water bays were not

experiencing slush buildup because of the low flow required by service water.

The licensee ensured de icing channel flow (recirculation from the outfall) was

available to the service water and circulating water bays. The licensee used fire

hoses to break up slush packs in the circulating water intake bays for more efficient

slush melting and placed main condensers in recirculation (use of one circulating

water pump for both condenser bays on each of the two condensers). This lineup

resulted in a higher outf all temperature as well as reducing the circulating water

intake flow by half. The lower cross-sectional flow area into the intake resulted in

less slush entrainment and higher outfall temperature, thus more efficient de-icing of

the circulating water bays. The licensee was not required to reduce power to

conserve condenser vacuum. The licensee determined that no operational effects  ;

were caused by this condition. I

Resident inspector activities involved observation of the slush entrained from the  !

river surface outside the intakes, inspection of the service water bay's lack of slush

buildup, inspection of de-icing channellineup and use of fire hoses to break up i

slush, and review of the licensee's immediate evaluation of service water

operability. Circulating water bay temperatures were 36 F after recirculation was

initiated, and de-icing flow was established and verified. No slush buildup occurred

_ _- - - - . .

.

i

.

2

'

in the service water bays. The concern regarding entrainment of slush did not

appear to apply to the service water bays due to the low cross-sectional flow areas

down to the intake, approximately 10 feet beneath the surface of the river.

The licensee stated that the major cause of the ice buildup was due to the lack of

4

the installation of an ice deflector upstream of the intake, normally installed in mid-

i

" November in anticipation of cold weather conditions, after the river level drops in

the late f all. The seasonal river level drop occurs by reduction of river flow

,:ontrolled by upstream dam throughput.

'

1

In mid-November, the licensee had identified that river levels would be too high for

installation of an ice deflector at the usual time.

, The NRC identified that the ice deflector was described in the Undated Safety

Analysis Report (USAR) as being in place to deflect ice during cold weather and was

to be in place during the winter months. The inspectors identified several other

issues associated with the ice deflector and the lack of evaluations in accordance

with 10 CFR 50.59. The licensee is continuing efforts concerning evaluation of this

condition as well as operational and maintenance procedure changes to address

installation and appropriate use of ice deflectors to prevent intake icing. This issue

'

will be followed in a subsequent resident inspection after licensee review and

corrective action activities have concluded (Unresolved item (URI) 298/96026-02).

c. Conclusion

.

-

The licensee's failure to install an ice deflector upstream before icing conditions

developed on the river resulted in a potential challenge to plant operation. Resident

inspection is continuing and wiii be addressed in the next inspection.

<

01.2 Notice of Unusual Event (NOUE) Concernino Fire in the Protected Area

a. Insoection Scope (93702)

Inspectors responded to observe the licensee's response to a fire in the protected

area.

b. Observation and Findinos

At about 2:50 p.m. (CST) on November 18,1996, during a full scale emergency

l exercise, a station operator noticed smoke in the turbine building hallway which

i shares a common wall with the main steam tunnel (secondary containment). At i

3:01 p.m., the source of the smoke was identified to be in the seismic gap between (

the main steam tunnel roof and the turbine building roof. The fire brigade '

responded to fight the fire. I

i

_ . _ _ _ . _ _ .__ _.____ _..= _ ._.._._. _ _ _ . _ . . _ . _ _ . .

1. . _ ..

1

.

!

-3-

At 3:11 p.m., a NOUE was declared due to a fire not being extinguished within

10 minutes. At 3:18 p.m., the fire was extinguished and a reflash watch set. The

. NOUE was terminated at 4:23 p.m. The licensee concluded that the operoi>ility of

l structures (reactor building, steam tunnel, and turbine building) was not degraded

by the fire.

The licensee has preliminarily determined that the fire was ignited by personnel

replacing the steam tunnel roof covering. Fibrous material, possibly debris, lodged

l in the 4-inch seismic gap between the buildings, was probably ignited by a torch

used to seal the roofing material. The negative turbine building pressure and

incomplete turbine building seal allowed smoke and, later, water from firefighting, to

enter the turbine building (not a Class I structure).

The licensee suspended roofing operations, initiated a root cause evaluation, and

planned not to continue roofing operations until the root cause of the fire was

identified and corrected.

The Senior Resident inspector, participating in the exercise, immediately responded

to the control room to observe the licensee's response to the event. The states of

Nebraska and Missouri were notified of both the initiation and termination of the

NOUE.

During the event, the full scale emergency drill was suspended, and the fully staffed

! technical support center and emergency operating facility stood by to assist if

necessary, in accordance with exercise contingency plans.

Two fire protection inspectors, onsite for a scheduled team inspection, will follow

the licensee's root cause evaluation and document it in NRC Inspection Report 50-

208/96-25. The NRC exercise evaluators will document the licensee's emergency t

response to this event in NRC Inspection Report 50-298/96-22.

c. Conclusion

The licensee's response to a fire in the protected area was timely and appropriate.

The fire brigade was not dispatched until the fire location was understood, the

emergency exercise in progress was suspended and did not distract the fire event

response, engineering was requested and responded immediately to the control

room, and the fire location, on a roof in a seismic gap between two adjacent

buildings, was quickly diagnosed. NRC emergency notifications were made in a

timely manner.

.

!

- , - -

=r -ey- v T-

1

.

1

i .

-4-

l

.

l

03 Operations Procedures and Documentation

j 03.1 Niaht Order Loo Not Uodated  ;

I a. Insoection Scone (71707)

The inspectors reviewed the night order log.

b. Observations and Findinas

On October 13,1996, a night order was entered to document that, if the outside '

temperature dropped to below 20 F, both trains of standby gas treatment systems '

,

would be declared inoperable due to the insulation rating on Sump Z. The insulation

l problem was corrected on October 20, but the night order log was not updated until

questions were raised by the inspector on October 24.

The Operations Manager stated that failure to update logs was an infrequent l

occurrence and the night order log was immediately updated. l

Additionally, inspectors noted that November 26 actions by operators required to

mitigate the slush buildup in circulating water bays, such as use of fire hoses and  !

alignment of condenser backwash, were recorded in shift supervisor logs, but were l

not documented in night orders to provide information to future crews. Until

procedure changes were implemented,information to crews was needed as an

interim corrective measure, inspectors noted documentation of required slush

buildup response in night orders on December 2.

c. Conclusion

The inspectors concluded that operations did not update the night order log in a

timely manner.

04 Operator Knowledge and Performance

.

04.1 Work Packaae Deficiencies identified by Operations

1

a. Inspection Scone (71707)

1

Inspectors reviewed instances where control room crews identified deficiencies in

packages and returned them for correction.

l

'

b. Observations and Findinas

The inspectors noted two instances where work packages submitted to the control

room for work had not properly identified the need to enter a Technical Specification

! action statement and an instance in which a work package intended to use test

i

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

.

+

5-

i

equipment on control rod drive circuitry did not include an evaluation of the I

configuration in accordance with the requirements of 10 CFR 50.59. The control  !

'

room documented these deficiencies in problem identification reports for corrective

action to strengthen the work control process. - The individual work packages were

returned to work control for correction.

c. Conclusion

The control room crew demonstrated appropriate safety standards and a good

questioning attitude in identifying these deficiencies.

04.2 Emeraency Diesel Generator Failure Evaluation

a. Inspection Scope (71707)

i

The inspectors reviewed Technical Specification Surveillance Requirement 4.5.F.1.c

to determine if the surveillance requirement was properly performed for two

occasions. The inspectors held discussion with licensee management and control

room shift supervisors and reviewed applicable procedures, evaluations, and training

documents,

b. Observations and Findinas

Technical Specification Surveillance requirement 4.5.F.1.c requires that, with one

diesel generator inoperable, determine within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the operable diesel

generator is not inoperable due to a common cause failure or perform Technical

l Specification Surveillance Requirement 4.9.A.2.a.1, to demonstrate operability of

'

the remaining diesel generator by actual operation.

On October 21,1996, Diesel Generator 2 was declared inoperable by the shift

supervisor due to a fuelleak. The leak was repaired. On October 23, during the

postmaintenance test, the motor potentiometer failed, preventing test completion j

i

and verification of diesel operability. The inspectors evaluated these two f ailures to  !

l determine if Technical Specification 4.5.F.1.c was properly performed. The

j inspectors found no written common cause determinations and no documentation

that common cause determinations were performed. Additionally, Technical

'

Specification 4.9.A.2.a.1 was not performed on the operable diesel generator, ,

'

which was required if a common cause determination was not performed.

The Operations Manager, system engineer, and shift supervisor on duty when the

first failure occurred each stated they had performed a common cause determination

,

and determined that the other diesel generator was operable. Each failed to

j document the determination. The system engineer concluded that the failure was a

i

potential common cause problem (there have been similar f ailures on both diesel

generators in the past), but the occurrence of the failures was infrequent and did

?

l

\

t. - . _ _ _ _ _ .__ , - - _ _ _ _ _ ~ _

,. _ ._, ,

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

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

.

.

[

'

6-

i

1

j not result in inoperability. The system engineer did not communicate the results of

i his determination to Operations.

l After discussions with licensee management, a formal common cause determination

, was performed on November 25 for the fuelleak and, at the end of the inspection

j period, the motor operated potentiometer common cause determination was in the

4

review process.

,

The inspectors interviewed shift supervisors and found a wide variance on the

.

understanding of the existence of guidance or procedures on how to perform the

surveillance requirement and the format, if required, of documentation that a

1 common cause determination had been performed,

i

l Based on the lack of written common cause determinations, lack of documentation

that common cause determinations were performed, lack of written guidance or

]_ procedures, and lack of performance of Technical Specification 4.9.A.2.a.1 on the

4 operable diesel generator within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a diesel generator was declared

inoperable, the inspectors concluded that Technical Specification 4.5.F.1.c was not

. met within the time frame required for both failures. The failure to perform a

l common cause determination or perform Technical Specification 4.9.A.2.a.1 within

l 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for both failures of Diesel Generator 2 on October 21 and 23,is a violation

1 of Technical Specification 4.5.F.1.c (298/96026-01).

4

c. Conclusions

'

Inspectors identified that, after two separate failures on Diesel Generator 2, the

,

licensee did not perform common cause evaluations for Diesel Generator 1. The

evaluations are required by Technical Specifications. Additionally, the licensee had

not provided written guidance to the operators on Technical Specification 4.5.F.1.c

implementation. Shift supervisors had an inconsistent understanding of how to 1

implement this requirement.

04.3 Failure to Recoanize Electrical Dependence of Reactor Eauioment Coolina Heat

Exchanaer B on Diesel Generator 2 Ooerability

a. Insoection Scope (71707)  ;

The inspectors reviewed the Technical Specification tracking logs and clearance I

order logs and held discussions with the control room staff.  !

!

b. Observations and Findinas

On November 18,1996, the inspector noted that the control room had authorized

removal of Diesel Generator 2 from service at the same time that Reactor Equipment

Cooling Heat Exchanger A was inoperable with the service water isolated. The

Technical Specification for the Reactor Equipment Cooling Heat Exchanger A

1

l

.

l

.

-7- \

l

required that the opposite train heat exchanger be operable, including its associated

emergency power supplies. Removal of the Diesel Generator 2 from service brought

into question compliance with this Technical Specification requirement. Inspectors .

questioned the appropriateness of this activity. l

The licensee determined that this activity was not permitted by Technical l

Specifications and wrote a problem identification report. The licensee did not '

remove Diesel Generator 2 from service until after Reactor Equipment Cooling Heat

Exchanger B was returned to service 3 days later.

c. Conclusions

The licensee's failure to identify an operability dependence on Diesel Generator 2

during an abnormal system line-up until after questioning by the NRC inspector was I

an example of ineffective evaluation of safet/-related system dependencies.

04.4 Division i Reactor Protection System (RPS) EaWoment Problems

l

a. Inspection Scope (71707)

The inspectors reviewed the Technical Specification, control room logs, and

annunciator printout and interviewed the control room staff.  ;

l

b. Observations and Findinos i

I

On November 22, during a surveillance test of Division 1 Average Power Range j

Monitor (APRM) E, alarms indicated an unexpected condition in the Division I RPS.

Instrument and Controls technicians correctly diagnosed that the low side voltage to j

the Division 1 flow bias unit power supply appeared to have failed. The unit l

provided scram signal input for all three APRMs in Division 1, not only to APRM E,

which was under a surveillance test and in bypass at that time.

The shift supervisor allowed troubleshooting to initiate on that flow bias unit while

concurrently determining the need to enter a Technical Specification action

statement. A half scram is required while a flow bias trip unit is inoperable. The

flow bias unit problem was identified and corrected in approximately 40 minutes.

During this time, the RPS Division I flow bias affected by this failure was not placed

in a trip (half scram) condition.

The licensee stated that, because the instrument and control technicians had

asserted a high likelihood of identifying and correcting the problem in a timely

fashion, the decision to determine the correct Technical Specification action, in

parallel with instrument and control troubleshooting and repair activities, was

appropriate.

Additionally, the licensee stated that 3 days after the occurrence, engineers were

not able to determine if the unit actually had been inoperable and, therefore, the

i

l

l

I

,

l

1

1

l

l

-8-

l

shift supervisor would not be expected to declare it inoperable. The Technical

Specification 3.1 request for inoperable flow bias scram circuitry requires promptly

placing the affected RPS division in a trip (half scram) condition. To have initiated

troubleshooting conditions without first identifying and complying with the action

statement associated with inoperable eq Jipment appeared to have been

nonconservative. Since the condition was fixed within 40 minutes, the action

statement requirement to complete a reactor plant shutdown within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> was

not reached. However, risk associated with troubleshooting activities in panels l

without placing the affected RPS division in half scram resulted in a vulnerability to

misdirected troubleshooting or the potential failure of RPS to function under a

transient condition.

c. Conclusion l

Failure to place the Division i RPS in a half scram condition when a failure was

suspected but actual cause unknown, and allowing troubleshooting and repair

activities in this condition for 40 minutes appeared to have been nonconservative

operations. Operability aspects of this issue were being evaluated at the close of

this inspection report and will be followed in the next resident insp' . tion report 1

(Inspection Followup ltem (IFI) 298/96026-07). 1

08 Miscellaneous Operations issues

08.1 (Closed) Licensee Event Report (LER) 95-012-00: RPS trip signal and primary

containment group isolations during shutdown for refueling outage. During a

scheduled end-of-cycle shutdown, and after manual plara trip, operator actions in

response to feedwater pump anomalies resulted in a feedwater controllockout, low

reactor vessel level, and subsequent group isolations. These actions were based on

simulator modeling which was not representative of feedwater system response, as

well as f ailure to incorporate lessons learned from prior plant shutdowns into plant

procedures. The plant was stabilized and procedures revised to address lessons

learned. This issue appeared to be of minor safety significance, therefore, this issue

is closed.

08.2 (Closed) Violation 50-298/94019-01: Failed to maintain positive pressure in control

room. The corrective actions for this violation were verified and documented in

NRC Inspection Report 50-298/94-31. Therefore, this issue is closed.

08.3 (Open) Violation 298/9508-01: lack of proper correction for emergency procedure

for station blackout. The inspectors reviewed Procedure 5.2.5.1," Loss of All AC

Power (Station Blackout)," Revision 11. On November 27,1996, during the

followup, the inspector noted that the commitment documented in the Safety

Evaluation Report which stated that the high pressure coolant injection pump would

be run for one cycle (estimated at about 10 minutes) had not been implemented in a

clear manner. The procedure stated that reactor vessellevel should be recovered

using the high pressure coolant injection pump with subsequent transfer to the

.

i

-9-

1

I

reactor core isolation cooling system for level and pressure c'ontrol. No time limit of

approximately 10 minutes or one cycle was provided in the procedure. The licensee

l

noted that reactor operators had been trained to promptly place the reactor core  !

isolation cooling system on line after high pressure coolant injection had recovered

vessel level, which would occur within once cycle under design basis conditions,

and stated that simulator training had emphasized the need to promptly secure high

pressure coolant injection when the reactor core isolation cooling system cam on

line. Since the licensee's design basis assumes the reactor core isolation cooling

system is operable, the licensee stated that allowance of use of high pressure

coolant injection if reactor core injection cooling was unavailable, would be an

l

acceptable practice since it would be outside the design basis and, therefore, not be  !

included in the Safety Evaluation Report.

l

The inspector noted that the reasons for securing the high pressure coolant injection

system stated in the Safety Evaluation Report included the high pressure coolant

injection system room heatup, as well as concerns that high pressure coolant

injection would reduce battery capacity during operation.

The licensee revised the emergency procedure to reflect that high pressure coolant

injection be used for only one cycle, approximately 10 minutes, in accordance with

the safety evaluation, and noted in the procedure that additional use of high

pressure coolant injection would be under 10 CFR 50.54(x). This appeared

appropriate.

Violation 298/9508-01 remains open pending review of the remaining examples;

however, this example of the violation is closed based on the licensee's corrective

action.

II. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments

a. Inspections Scope (62707 and 61726)

l

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

Procedure Title

6.2 ADS.304 Automatic Depree.surization System Water Level

Calibration and Functional

6.1 DG2 Diesel Generator 1 Surveillance Run

. . _ _

.

! .

.

.

- 10-

l

6.2CSCS.301 Core Standby Cooling System Water Level Calibration

and Functional

MWR 96-0708 Replacement of Pressure Switch for Reactor Pressure

Permissive

MWR 96-0711 Replacement of Pressure Switch to Low Set (NBI-OS-

51D)

l MWR 06-1608 Replacement of a Pressure Switch (NBI-PS-51C) Switch

Metering Valve

MWR 96-1627 Diesel Generator Fuel Leak Repair

MWR 95-1465 Reactor Equipment Cooling Heat Exchanger Outlet

Valve Replacement

b. Observations and Findinas

The inspectors observed all or portions of several maintenance activities, in

general, maintenance was accomplished according to procedures and using

appropriate radiological controls practices. Tagout boundaries and system lineups

appeared to have been implemented correctly. Reference materials were

appropriate, and parts used were controlled in a manner that indicated proper

materials were used to support the observed activities. Postmaintenance testing

appeared to address proper requirements. Exceptions to the above general findings

art; documented in other sections of this report.

c. Conclusigns

Maintenance observed by inspectors appeared appropriate, with exceptions noted in

this report.

M1.2 Adeauacy of Tolerances for Core Sorav Actuation Instrumentation

a. Insoections Scope (61726)

On November 4,1996, the inspectors observed performance of

Procedure 6.2CSCS.301,"CSCS Water Level Calibration and Functional (Div 2),"

Revision 0.2, which calibrates and functionally checks Level Indicating Switches

NBI-LIS-72B and -72D and their associated indicators (Yarway).

b. Observations and Findinas

The inspectors observed portions of the surveillance at Instrument Rack IR-25-6A.

While observi tg indicator calibration during Step 8.1.21, the inspector noted that

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

m .

3

.. i

i l

- i

'

'

-11-

f

l i

I  !

i

'

the maintenance technicians did not record the first "as found" reading (increasing),

l which was outside the procedure calibration tolerance. The maintenance i

l technicians increased the calibration pressure and then decreased the pressure. The

i' second reading (decreasing) was within the calibration tolerance. The maintenance

j technicians recorded the second indicator reading in the procedure "as found"

reading. This was peformed without specific steps _in the procedure. The '

i maintenance technicians stated that they were trained to perform these steps based

! on an introduction of a hysteresis effect. The licensee was unable to explain why

j the hysteresis effect did not always occur.

'

.

i

a  !

l The licensee stated that the safety consequences of hysteresis is minor because the  !

i levelindicator does not actuato safety signals. Also, the licensee determined that  ;

l the level indicators were used only for Procedure 5.2.5.1, " Loss of All AC Power j

j (Station Blackout)," and calibration tolerances of 3 percent of scale appeared to be

, too conservative.  !

I  !

! The inspector identified that Step 8.1.28.3 involving valve manipulation, test

} equipment removal, and independent verification could not be performed as written. 5

f

The licensee stated that these actions were included in one step, in an ambiguous  ;

manner, and stated that technicians had performed the originalintent of the step

properly. The safety consequence is minor based on the independent verifier  !

,

'

verifying the correct part of the step, but a weakness was identified by the  !

inspector for not stopping and changing the procedure. The licensee stated that the

step would be changed.

c. Conclusions

i

The inspectors concluded that the licensee's understanding of the safety function at  ;

i the level indicators and the basis for the calibration tolerances was weak and the

j fact that the independent verifier failed to stop and change the procedure when the

procedure could not be performed as written showed a lack of rigor in procedure

use.

,

'

Since inspectors identified that the level indicators used in emergency operating

procedures, for reactor fuel range level, are the same design as the indicators

. discussed above, this issue will be followed in a subsequent report i

j (IFl 298/96026-06). )

!

i M1.3 Contradictorv Administrative Procedure Reauirements Allowed Performance of

i Surveillance Procedure Steps Out of Seauence

2

a. Inspection Scooe (62707)

On November 6,1996, the inspectors observed portions of Maintenance Work

'

]

j Requests MWR 96-0708 and MWR 96-0711.

?

i

4

-- -- . _ - ,

~

,

!

.

l

-12- ,

l

i

b. Observations and Findinas

During the performance of the maintenance work request, the inspectors noted that I

the maintenance technicians were performing steps out of sequence and the work ,

packages did not specifically address whether work could be performed in any I

order. When questioned by the inspector, the maintenance technicians stated

Procedure 0.40, " Work Control Program," Revision 5, allowed them to perform the )

steps in any order.

I

The inspectors reviewed the licensee's procedures and guidance on procedural

adherence, which included Procedure 0.1, " Introduction to CNS Operations

,

Manual," Revision 14, CNS Directive Number 12, " Requirements for the Use of I

Procedures," Revision 1, and Procedure 0.40. Procedure 0.40, Step 8.5.14, stated,

in part, that work instructions may be performed out of sequence. Procedure 0.1

and CNS Directive 12, both stated that deviation from or omission of work

instruction steps is not acceptable unless flexibility was provided within the work

instructions.

-

The inspectors questioned the licensee regarding the three procedures. A problem

identification report was initiated to document the contradiction and to correct the

procedure problem to preclude steps out of sequence without specific guidance.

c. Conclusion

.

The inspectors concluded that the steps that the maintenance technicians were

performing out of sequence were of low safety consequences. This finding

illustrates an administrativo procedure inconsistency, which provided improper

guidance for work on safety systems,

j l

,

M7 Quality Assurance in Maintenance Activities

a. Inspection Scoce (62706)

,

inspectors reviewed problem identification reports initiated during this inspection

'

period.

b. Observations and Findinas

inspectors noted that throughout this inspection period the instrument and control

shop continued to identify a large fraction of problems with plant procedures,

design, and individual performance. Their problem identification reports evidenced

consistently high standards for problem identification. Several problems identified

involved well-focused issues concerning adequacy and enhancement of procedures

and individual performance. Problem identification has consistently improved and

'

has reached a strong level of performance in the instrument and control area.

.

.

-13-

c. Conclusion

The instrument and control shop demonstrated a strong questioning attitude by the

high quality and number of problems which were self-identified in systems,

procedures, and personnel performance.

M8 Miscellaneous Maintenance issues (92902) *

!

M8.1 (Closed) LER 95-004-00: primary containment group isolations caused by  !

surveillance procedure deficiencies. This procedure performed a reactor coolant

system hydrostatic test and also performed excess check val:e leakage testing on

instrument lines. Isolations had occurred because the procedure allowed

performance of sections out of sequence, but did not properly isolate the system

within sections to prevent group isolations. The steps to isolate the system were  ;

located in an earlier section. The licensee revised the procedure to ensure initial

l

conditions isolated the instrument lines before testing. 1

1

The licensee's failure to provide instructions which precluded unexpected group

isolations is a violation of 10 CFR Part 50, Appendix B, Criteria V, which requires, in

part, that activities be controlled by procedures appropriate to the circumstances.

This licensee-identified and corrected violation is being treated as a noncited

l

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

(298/96026-05).

M8.2 (Closed) LER 95-006-00: improper methodology for calibrations of source range

monitors which resulted in missed Technical Specification surveillance requirements.

This report describes a failure by the licensee to test a preamplifier in the source

range monitor circuit when performing Techrsical Specification surveillance tests.

The lack of full surveillance testing was addressed as a programmatic issue in 1994,

the year in which this issue was raised. NRC Inspection Report 50-298/94-31 l

l Section 4.2 addresses this programmatic issue and its satisfactory resolution. Since l

l this issue was one of many identified by the licensee in that time frame associated

with their corrective action, no further NRC action concerning this report is required.

This issue is closed.  !

M8.3 (Closed) LER 96-008-00

scram discharge volume high level RPS trip channel

l anomaly. During a surveillance procedure, the licensee identified that an isolation  !

valve to a scram discharge valve level switch had failed in the closed position. This

was revealed by the switch actuating unexpectedly during the surveillance

procedure, causing a half scram. The licensee dislodged the valve and returned it to

the open position. The licensee also addressed the vulnerability that similar valves

may f ail in the closed position with an engineering evaluation and revised  ;

procedures to diagnose similar failures. This issue was properly corrected.

'

I

4

. .. - . .

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

..

i

.

,-

4

l - 14-

4

l 111. Enaineerina

! 'E2 Engineering Support of Facilities and Equipment

E2.1 Installation of Ice Deflector Uostream of Intake Structure

a. Inspection Scope (37828)

l The inspectors reviewed the licensee's engineering of an support of an installation

j of an ice deflector upstream of the intake structure.

) b. Observations and Findinas

On November 26,1996, the licensee experienced slush buildup in the circulating

j water bays of the intake structure. This event is more fully described in

i Section 01.1 of this report. The inspectors questioned the lack of an ice deflector

as described in the USAR to preclude ice buildup in the intake structure and

] questioned if an evaluation in accordance with 10 CFR 50.59 had been performed

j regarding the lack of this deflector during the cold weather. The licensee stated

that an evaluation had not been done, but agreed that it should be addressed. The

l inspectors reviewed the licensee's assessment that service water intake icing was

not a concern based on the low cross-sectional flow area for slush entrainment

j 10 feet beneath the surface of the river. The inspectors noted that the service

a water bay temperature of 36 F was not conducive to ice formation or deposition in

i the event river water level dropped before ice deflector installatica. Fuaher, the

i licensee stated that the ice deflector, used for the past several years, would be

installed when river water dropped approximately 2 more feet, which would allow

'

,

ice deflector barges and booms to be attached to structures already on the river

j bank. Although the ice dropped, the licensee determined that the deflector should

not be installed until after Station Operations Review Committee approval of the ice

i deflector. This had ne. occurred as of De : ember 10, precluding evaluation and

installation of the ice deflector. This issue encerning procedures, evaluations, and '

l ice deflector installation will be followed in e subsequent resident inspection report

j under URI 298/96026-02.

1

j E4 Engineering Staff Knowledge and Performance l

) l

Licensee Actions to Identify a Valve Vulnerable to Pressure Above Desian Marain I

. E4.1

} a. Inspection Scope (37751)

.

l The inspector reviewed a :tions the licensee took to identify and respond to an

engineering issue.

5

$.

- - - , ,,m-

. . - - . -- . - - -

. 1

i

! -

j

.  ;

i

-15-

,

I

b. Observations and Findinas  ;

,

I

j On November 24,1996, the licensee identified that a sample line for reactor coolant '

L appeared to have an inadequate relief valve setpoint, which may allow the pressure

i regulator on that line to exceed maximum valve operability pressure. The licensee

i identified that Pressure Regulator PC-PRV-PCB-632 may exceed design pressure '

,

' because the relief valve, PC-RV-17RV, was set too high, which could exceed design .

pressure for Valves RR-SOV-SPV-740 and -741, potentially causing them to fail l

, close or to spuriously open. I

i

l After identification of this issue, the licensee isolated the sample line and issued a

report in accordance with 10 CFR 50.72, since the failure of the automatic isolation

i valve may have allowed the design pressure to be exceeded. The licensee planned

i to modify the system in the upcoming outage. The licensee stated that this sample

j pathway was not required under design basis conditions and, therefore, no design

4

'

or operation requirements were affected by isolation of these lines. The licensee

documented this finding in Problem identification Report 2-07855 and appeared to

I

have taken appropriate action to address this concern, inspectors concluded that

vulnerability to this failure did not pose an immediate safety concern. The

licensee's actions to isolate the line eliminated the vulnerability. Further inspector

review of this issue will be followed during closure of the associated LER.

i

l c. Conclusions

t

j The licensee identified a design problem in the plant associated with a reactor

! coolant sample line and took appropriate corrective action to change the valve

lineup to assure the valve was isolated, initiate engineering review, and issue a

! notification in accordance with 10 CFR 50.72.

< i

E8 Miscellaneous Engineering issues

E8.1 (Closed) LER 298/94-035-00: inoperable standby gas treatment system due to a

j potential backflow of water from Sump Z under design basis accident conditions.

The licensee discovered that, under design accident conditions with a coincident

loss of offsite power, Sump Z pumps and high level alarm would lose power. This

could allow the condensation from the standby gas treatment effluent cooling to

4

collect in the underground piping and accumulate in the sump, filling the standby

gas treatment drain and discharge lines and rising backpressure above system

j design valves. Therefore, the standby gas treatment system operability could not

j be assured, which could cause secondary containment to be inoperable,

i

) The inspectors verified that the following corrective actions were completed:

i

(1) a printout from the equipment data file showed that the appropriate

components in Sump Z system were classified as essential;

!

4

e

. _ - - _ . .

s

.

-16-

(2) replacement of insulation and heat tracing on the sump pump discharge line

was done under Maintenance Work Request 95-C262 and Design Change  ;

DC 95-033:  ;

(3) Procedure 5.1.3, " Flood," Revision 20.2, was revised to include actions to

take during an external flooding event to maintain standby gas system i

operability;

(4) a tailgate session was held on February 23,1995, which provided training to l

plant personnel involved in the development / validation of design change

documents on the interaction of nonessential systems with safety-related I

systems; and l

1

(5) training of operations personnel and engineering personnel on this event in

Lesson Plar:: INTRO 23-99-26," Industry Events," Revision 1, and INTRO 35-

95-16, "CR 94-1282," Revision 0.0, for the operators and engineers,

respectively.

NRC inspection Report 50-298/94-31 documented that inspectors reviewed two

design modifications and documentation generated by the licensee to check for a

generic concern of the failure of nonessential components affecting essential

components in other systems. The inspectors did not identify any concerns.

The licensee's failure to properly translate design specifications into plant  !

configuration is a violation of 10 CFR Part 50, Appendix B, Criterion lil, which j

requires, in part, that the design basis for those structures, systems, and l

components to which this appendix applies are correctly translated into

specifications, drawings, procedures, and instructions, that appropriate quality

standards are specified and included in design documents, and that deviations from

such standards are controlled. This licensee-identified and corrected violation is I

being treated as a noncited violation, consistent with Section VI.B.1 of the MC

Enforcement Policy (298/96026-03).

E8.2 (Closed) LER 298/95-018-01 and 00: maintenance activity could compromise

steam tunnel blowout panel. This event was discussed in NRC Inspection Report

50-298/96-04and escalated enforcement action was issued to address this concern

(EA 96-062). Resolution of this issue will be closed under Violation 298/960004-

01. No new issues were revealed by the LERs.

1

E8.3 (Closed) LER 298/96-014-00: fuel preparation machine upper limit stops set in

violation of Technical Specifications. The licensee has issued a revision to this LER.

'

The issue will be addressed by closure of the revision.

'

E8.4 (Closed) LER 298/96-010-00: previous unavailability of the muffler bypass valve on

Diesel Generator 2 due to bowing in actuator shaft. After a Diesel Generator 2

surveillance, the licensee tested the muffler bypass valve, a safety-related valve

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

l

. .

.'

.

I

'

17-

!

i

j which provides an analyzed diesel exhaust path. The valve failed to operate. The ,

licensee identified that prior testing had not been performed while the valve was ~j

l heated by diesei operation, and the bow in the shaft was not identified during {

4

dedication activities to upgrade the originally nonsafety-related valve installation. i

i The licensee found that the similar valve for Diesel Generator 1 operated properly l

, while hot. The cause was identified as a slightly botved valve shaft which did not

j affect operation while the valve was cold. The licensee has failed both valves to  !

I the open (safety) position and performed an analysis in accordance with  !

10 CFR 50.59, while determining a replacement configuration for the use of muffler j

valves.

l

,  !

,'

The licensee's failure to properly translate design specifications into plant- l

'

configuration is a violation of 10 CFR Part 50, Appendix B, Criterion lil, which

l requires that the design basis for those structures, systems, and components to l

which this appendix applies are correctly translated into specifications, drawings, j

^

procedures, and instructions, that appropriate quality standards are specified and  ;

included in design documents, and that deviations from such standarda are l

I

controlled. This licensee-identified and corrected violation is being treated as a

noncited violation, consistent with Section Vil.B.1 of the NRC Enforcement Policy

(298/96026-04). i

i

E8.5 (Closed) LER 50-298/94-004-00: reactor scram due to partial closure of turbine

governor valves. The licensee identified that the governor valve partial closure,

resulting in a reactor scram, was caused by a failure of a digital component in the  !

nonsafety-related turbine electrohydraulic control system. Feedwater proHems and l

subsequent group isolations at low reactor vessel level, which occurred after the {

scram, were found to be caused by an improper setpoint in the feed pump lock and  !

hold circuitry. The licensee performed corrective action for these concerns. No

ariforcement for this issue was indicated.

SQdV Y IV. Plant Support

R2 Status rotection and Control Facilities and Equipment

R2.1 Health Physics

a. Inspection Scoce (71750)

The inspector located a personnel thermoluminescent dosimeters detached from a

worker's badge.

b. Observations and Findinos

On November 26,1996, the inspector found a personnel thermoluminescent

dosimeter in the service water pump area. This thermoluminescent dosimeter had

apparently become detached from an individual's badge. The licensee concluded

l

i

- .. . .- - -

,

- l

': l

.  ;

,

<

)

-18- )

,

l

<

4

!

that the individual had lost the dosimeter shortly before its discovery by the

inspector, since security records indicated entry into the service water pump room

on the prior day. Past entries into the service water pump room had also occurred,

i

The licensee had also verified that the individual had not entered the radiological

I controlled area within the past several days and, therefore, estimated that additional

5

exposure had not been obtained while the individual was not monitored with

i thermoluminescent dosimeters.

t

c. Conclusions

inspectors identified that the licensee failed to identify that an individual's dosimeter

became detached, resulting in lack cf monitoring for up to a few days. This issue is

minor.

1

i

R4 Staff Knowledge and Performance in Radiation Protection and Control

4

i R4.1 Radiation Protection Coveraae durina Maintenance Activity

,

a. inspection Scope (71750)

,

.

On November 6,1996, the inspectors observed contamination control concerns ,

'

i during portions of Maintenance Work Requests MWR 96-0708 and MWR 96-0711. l

i

'

b. Observations and Findinas

1

The maintenance technicians were replacing two pressure switches filled with j

potentially contaminated water. Radiation protection has been contacted and l

technicians could proceed. If any water was spilled, radiation protection was to be l

i contacted. The maintenance technicians verified the verbal instructions with

, radiation protection prior to disconnecting the pressure switches. A radiation

proter, tion technician was dispatched to assist in ensuring that all of the system

! watr,r was captured. The radiation protection technician appropriately captured the  !

'

wMer as the pressure switches were removed, but failed to drain the first pressure '

switch. As the pressure switch was handed from one maintenance technician to

l another, potentially contaminated water was spilled on the work package. The

i radiation protection technician was not alerted. As the radiation protection

technician turned to leave the work ares, the inspector called him back and pointed

out the need for a survey of the work package for contamination. The werk l

package was found to be free from contamination.

i

c. Conclusion

l The inspectors concluded that the maintenance technicians took the appropriate

I actions in verifying that the verbal instructions were correct, but failed to point out

'

that water was spilled on the work document to the radiation protection technician.

<

l

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

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

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

'

1

l -19-

i

The safety consequences of this particular event were low because the work

document was not contaminated, but demonstrated a weakness in preventing the

j. spread of contamination.

4

F8 Miscellaneous Fire Protection issues

i

F8.1 (Closed) LER 298/94-036-02.-01. and -00: fire suppression water system did not

meet the minimum requirements for operability. The electric-driven fire pump and

the fire water jockey pump lost power due to an electrical transient on the 12.5 kV

l'

system and during planned power outages to perform maintenance on the 12.5 kV

,

system. '

The licensee made these three reports to comply with Technical Specifications

Action Statement 3.15.C.2.b, which required a special written report that outlines

the action taken, the cause of the inoperability, and the plans and schedule for

restoring the system to operable status. The inspectors concluded from a review of

the LERs that the licensee met the Technical Specification action statement. In

each case, power was restored and the electric-driven fire pump and fire water

jockey pump were returned to an operable status.

3 V. USAR

A recent discovery of a licensee operating facility in a manner contrary to the USAR

description highlighted the need for a special focused review that compares plant

j practices, procedures, and/or parameters to the USAR description. While

'

performing the inspections discussed in this report, the inspectors reviewed the l

applicable portions of the USAR that related to the areas inspected. The licensee '

identified a number of USAR discrepancies in the licensee's corrective action for a

1994 TS surveillance violation. The inspectors verified that these discrep 'e s

were not corrected to date. These discrepancies will be documented in N.

i

inspection Report 50-298/96-24,the safety system functional inspection.

Section 01.1 discusses that the USAR describes that operation of the facility in cold i

weather is with the intake structure ice deflector in place. On November 26,1996,

some ice slush collected at the intake and the ice deflector was not installed. This

,

is an unresolved item.  !

r

VI. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

exit meeting on December 2,1996. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

___ - .-.

.. -

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

.

9

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Jack Dillich, Maintenance Manager

Rick Gardner, Operations Manager

Robert Godley, Plant Engineering Manager

Mike Hale, Radiation Protection Manager

Bradford Houston, Licensing Manager

Mike Peckhart., Plant Manager

INSPECTION PROCEDURES USED

IP 37751: Onsite Engineering

IP 37828: Engineering - Install and Test Modifications

IP 61726: Surveillance Observation

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92901: Followup - Plant Operations

IP 92902: Followup - Maintenance

IP 92903: Followup - Engineering

IP 92700: Onsite Followup of Written Reports of Non-Routine Events at Power Reactor

Facilities

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

ITEMS OPENED, OPENED AND CLOSED, CLOSED, AND DISCUSSED

Opened

298/96026-01 VIO no documentation for Technical Specification surveillance

requirement (Section 04.2)

298/96026-02 URI slush buildup in circulating water intake bays (Section 01.1)

298/96026-06 IFl design basis for level indicator calibration tolerance for fuel

range level indicators (Section M1.2)

298/96026-07 IFl f ailure of APRM flow bias unit low side voltage operability

evaluation (Section 04.4)

Opened and Closed

298/96026-03 NCV single failure of standby gas (Section E8.1)

298/96026-04 NCV Diesel Generator 2 muffler bypass valve bowed shaft

(Section E8.4)

298/96026-05 NCV primary containment group isolations caused by inadequate

surveillance procedures (Section M8.1)

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

,

• :

• I

.

.

4-

g -2- l

l

l

] Closed

)

298/94019-01 VIO failure to maintain positive pressure in control room i

.

(Section 08.2) 1

I

298/94-004-00 LER reactor scram due to partial closure of turbine governor valves i

!

(Section E8,5)

l 298/94-035-00 LER inoperable standby gas treatment system (Section E8.1)  ;

298/94-036-02,

-01,-00 LER fire suppression water system did not meet the minimum {

requirements for operability (Section F8.1)

298/95-004-00 LER primary containment group isolations caused by surveillance .1

3 procedure deficiencies (Section M8.1)

2

298/95-006-00 LER improper methodology for calibrations of source range

monitors which resulted in missed Technical Specification )

.

surveillance requirements (Section M8.2)

) 298/95-012-00 LER RPS trip signal and primary containment group isolations during

a shutdown for refueling outage (Section 08.2)

.

'

298/95-018-00,-01 LER . maintenar:ce activity could compromise steam tunnel blowout

panel (Section E8.2)

4

298/96 008-00 LER scram discharge volume high level RPS trip channel anomaly

(Section M8.3)

298/96-010-00 LER previous unavailability of the muffler bypass valve on

4

Emergency Diesel Generator 2 due to bowing in actuator shaft

(Section E8.4)

3_

298/96-014-00 LER fuel preparation machine upper limit stops set in violation of

Technical Specifications (Section E8.3)

!

'

Discussed

!

! 298/9508-01 VIO Inadequate Procedures (Section OB.3)

1

3

i

!

l

i

l

I