ML20235R766

Insp Rept 50-298/89-01 on 890101-0205.Deviation Noted.Major Areas Inspected:Plant Status,Operational Safety Verification,Monthly Surveillance & Maint Observations & Safety Sys Walkdown

ML20235R766
Person / Time
Site:	Cooper
Issue date:	02/23/1989
From:	Bennett W, Constable G, Greg Pick NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20235R746	List: ML20235R744 ML20235R753 ML20235R766
References
50-298-89-01, 50-298-89-1, NUDOCS 8903030414
Download: ML20235R766 (12)

See also: IR 05000298/1989001

Text

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APPENDIX B

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-298/89-01 Operating License: DPR-46

Docket: 50-298

Licensee: Nebraska Public Power District (NPPD)

P.O. Box 499

Columbus, Nebraska 68602-0499

Facility Name: Cooper Nuclear Station (CNS)

Inspection At: CNS, Nemaha County, Nebraska

Inspection Conducted: January 1-February 5,1989

Inspectors: WMW -

G 1 1 (3

G. A. Pjtf Resident Inspector, Project Section C, Date '

Divisten Reactor Projects

A/IJ/h

W. R. Bennett, Senior Resident Inspector, Project Date

Section C, Division of Reactor Projects

w

Approved: .

2/27/8'f

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G st31iTe, Chief _, Project Section C, Division Da'te /

o _ Reactor Projects

h3030414990227

o ADOCK 05000298

PNu

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Inspection Summary

Inspection Conducted January 1 through February 5,1988 (Re' port 50-298/89-01)

Areas Inspected: Routine, unannounced inspection of plant status, operational

safety verification, monthly surveillance and maintenance observations, and

safety system walkdown.

Results: The licensee operated the plant in a safe, controlled manner. The

licensee addressed a diesel generator failure in a thorough manner; however,

since a similar failure occurred 3 months previously, a potential weakness

still exists in the licensee's corrective action program. The licensee

demonstrated thoroughness and persistence in identifying the root cause of the

main steam isolation valve failure. The predictive maintenance performed on

diesel generators indicates a conscientious attitude towards safety and

reliability in the maintenance area. ~ As discrepancies related to the as-built

l effort are identified, the licensee is evaluating the problems for safety

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significance and impact in the plant. J

One deviation was identified for failure to lock or seal instrument valves as I

committed to in the USAR (paragraph 4).

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DETAILS

1. Persons Contacted >

Principal Licensee Employees

• G. R. Horn, Division Manager of Nuclear Operations

• G. S. McClure, Manager, Nuclear Engineering Department l

• J. M. Meacham, Senior Manager, Technical Support

• E. M. Hace, Engineering Manager

• R. Brungardt, Operations Manager

• R. L. Gibson, Audit and Procurement Quality Assurance Supervisor

• G. R. Smith, Licensing Supervisor

• C. R. Moeller, Technical Staff Supervisor

• L. E. Bray, Regulatory Compliance Specialist

J. R. Flaherty, Engineering Supervisor

• Denotes those present during the exit interview conducted on

February 6,1989.

The NRC inspectors also interviewed other licensee employees and )

contractors during the inspection period. l

2. Plant Status  ;

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l From January 1-25, 1989, the plant operated at essentially 100 percent I

power. On January 25,1989, at 6:53 a.m. the reactor scrammed en "APRM '

High High Level." The cause of the scram was determined to be a failed

main steam isolation valve (MSIV). The reactor was synchronized to the

l grid and power was being increased as of February 5,1989.

3. Operational Safety Verification (71707)

The NRC inspectors observed operational activities throughout the

inspection period. Proper control room staffing was maintained. Control

room activities and conduct were observed to be well controlled and

professional. The NRC inspectors observed five shift turnover meetings

and verified that information concerning plant status was properly

communicated to the oncoming operators. Discussions with operators

demonstrated that they were cognizant of plant status and understood the

importance of, and reason for, each lit annunciator. Control board

walkdowns and tours of accessible areas at the facility were conducted to

verify operability of plant equipment. Overall plant cleanliness was

observed to be good throughout the inspection period.

The NRC inspectors observed portions of the receipt, inspection, and

storage of new fuel on January 10 and 11,1989. The operators were

careful not to jar or damage the fuel during unpacking and transport of

the fuel bundles from the transportation crates to the fuel pool.

Unpacking and handling of the fuel bundles was controlled by Nuclear

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Performance Procedure (NPP) 10.22 " Receiving and Handling Unirradiated

Fuel," Revision 2, dated January 5,1989. The operators cleaned,

inspected, and assembled the fuel bundles, the bundle channels, and the

spring clips in accordance with NPP 10.23, "New Fuel Inspection,

Channeling, and Control Blade Inspection," Revision 2, dated December 29,

1988. Proper control of the receipt of special nuclear material was

implemented by the refueling floor supervisor. The receipt was conducted

in accordance with NPP 10.21, ."Special Nuclear Materials Control and i

Accountability Instructions," Revision 2, dated November 9, 1988. All

operators involved in the fuel receipt process were knowledgeable and

competent. The new fuel receipt process was performed efficiently. All

personnel involved in the new fuel receipt process had recently attended a

training session on inspecting new fuel conducted by General Electric.

On January 17, 1989, Emergency Diesel Generator (EDG) No. I shut down

approximately 21/2 hours into the performance of the monthly operability

surveillance test. The EDG shut down when a circumferential crack

occurred on the stainless steel fitting connecting a pressure gauge to the

overspeed trip valve. The cracked fitting allowed 30 psi control air to

bleed off from the overspeed trip valve. The loss of control air to the

overspeed trip mechanism shut off air to the fuel racks. The fuel racks

closed due to the loss of air, shutting off fuel flow to the cylinders and

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stopping the engine. This problem is similar to the event described in

l NRC Inspection Report 50-298/88-33.

l The licensee determined that the fatigue failures were caused by vibration

causing contact with other metal surfaces inducing stress risers and

subsequent f ailures. The licensee performed a walkdown of the starting

and control air systems on both EDGs. All problems identified were

corrected. Loose tubing was tied down, and tubing in contact with other

components was buffered by placing rubber gasket material between the

components at the point of contact. Additional inspections were performed

while the diesels were operating to verify that no contact was made.

Design modifications scheduled for the 1989 refueling outage will move

instruments and air lines from the EDG to instrument racks, significantly

i reducing the vibration. The licensee will inspect the DG piping during

l all planned DG runs prior to the next refueling outage. Another identical

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failure of EDG No.1 occurred on February 13, 1989. This later failure

occurred outside this inspection period and will be discussed in NRC

Inspection Report 50-298/89-09.

On January 25, 1989, at 6:53 a.m., the reactor tripped due to high-high

average power range monitor (APRM) readings. The NRC inspector responded

to the control room following the trip and verified that the control room

operators were taking appropriate actions in response to the reactor trip.

Initial indications were that all APRM channels had tripped on high level

for no apparent reason. The licensee decided to maintain the plant in a

hot standby condition while troubleshooting the cause of the scram.

Further review of recorded instrumentation indicated that a pressure spike

of less than .1 second duration had occurred simultaneously with the APRM

trip signals. This led the licensee to conclude that the pressure spike

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had caused voids to collapse in the reactor core, and this collapsing of

voids had caused a power increase causing the reactor trip. The licensee

then decided to cool the plant down to perform further troubleshooting of

the problem.

The licensee opened both "A" line MSIVs, on January 26, to cool. down the l

plant. With both MSIVs indicating open, the downstream pressure did not l

increase as expected, indicating potential steam line blockage'or MSIV  !

failure. The licensee then opened the "B" MSIVs, received the expected

pressure indication increase, and cooled down the plant to a cold shutdown

condition. Testing performed by the licensee indicated that the most

likely failure had occurred in the outboard MSIV (Valve 86A); therefore,

the licensee removed and inspected MSIV 86A. The inspection determined

that no failure had occurred in MSIV 86A. When it was discovered that the  ;

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problem was not in MSIV 86A, the licensee reinstalled MSIV 86A and

commenced disassembly of the inboard MSIV (80A) concurrently with

radiography of the of the "A" main steam line. Radiography revealed no

obstructions in the steam line. Disassembly of MSIV 80A revealed that the

valve stem had separated from the stem disc. The pin holding the stem

disc to the valve stem was missing. This apparently allowed the stem disc

to unthread from the valve stem until the main disc, no longer held by the

stem disc to valve stem arrangement, separated from the stem and fell into

the valve body, blocking the steam line. The licensee repaired and I

reinstalled MSIV 80A.

The NRC inspectors monitored the reactor startup following repair and

testing of MSIV 80A. The startup and power escalation was performed in a

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controlled, professional manner in accordance with operating procedures.

The reactor was declared critical at 1:53 p.m. (CST) on February 4,1989,

and synchronized to the grid at 10:41 a.m. on February 5.

The NRC inspectors verified that selected activities of the licensee's

radiological protection program were implemented in conformance with

facility policies, procedures, and regulatory requirements. Radiation

and/or contaminated areas were properly posted and controlled. Radiation

work permits contained appropriate information to ensure that work could

be performed in a safe and controlled manner. Radiation monitors were

properly utilized to check for contamination.

The NRC inspectors observed security personnel perform their duties of

vehicle, personnel, and package search. Vehicles were properly authorized

and controlled or escorted within the protected area (PA). Personnel

access was observed to be controlled in accordance with established

procedures. The licensee continued implementation of the security

equipment upgrade during this inspection period. The NRC inspector

conducted site tours to ensure that compensatory measures were properly

implemented as required due to equipment failure or the security upgrade.

Interviews with security pesonnel demonstrated that they were cognizant

of their responsibilities. The PA barrier had adequate illumination and

the isolation zones were free of transient materials.

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The licensee operated the plant in a safe, controlled manner during this

inspection period and took prompt action in response to NRC concerns. The j

failure of the EDG was addressed by the licensee however, since a similar )

failure occurred 3 months previously, a potential weakness may still exist 1

in the licensee's corrective action program. The licensee demonstrated i

thoroughness and persistence in identifying the MSIV failure which resulted )

in an almost undetectable pressure spike that caused the scram. j

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No violations or deviations were identified in this area. I

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4. Monthly Surveillance Observations (61726)

The NRC inspectors observed and/or reviewed the performance of the

following surveillance procedures (SP): 1

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. SP 6.3.4.1, "CS Test Mode Surveillance Operation," Revision 25, dated 1

October 17, 1988: This surveillance test was performed on

January 11, 1989, to meet the TS operability requirements and to

obtain quarterly inservice test (IST) data. The IST engineer took ,

vibration measurements from additional locations on the "B" Core i

Spray (CS) pump motor to provide extra data. The additional data was I

taken to enable a more thorough evaluation of the motor's lower I

bearing performance to be conducted by General Electric. The CS pump

is located in a contaminated area. The NRC inspector observed both j

the station operator and the engineer utilizing good radiological l

practices. The test equipment was verified to be within calibration. l

Good cooperation and communication was exhibited between the engineer

and the station operator. The NRC inspector reviewed the procedure

and determined that all reviews had been conducted and data was

within the required limits.

. SP 6.3.12.1, " Diesel Generator Operability Test," Revision 26, dated

January 5,1989: This test was conducted on January 17, 1989, to

determine that EDG No. I was operable as required by Technical

Specifications (TS). The diesel generator ran for approximately

21/2 hours when it shut down on a loss of control air. The diesel

was restarted at 7:25 p.m. and declared operable at 1:05 a.m. on

January 18, 1989. The NRC inspector reviewed the completed procedure

and determined that all reviews and approvals had been performed.

All data was within specifications. The problem identified

regarding loss of control air to EDG No.1 is discussed in more

detail in paragraph 3.

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SP 6.2.2.3.1, "HPCI Steam Line High Flow Calibration and

Functional / Functional Test," Revision 26, dated April 14, 1988: This

surveillance was performed as a functional test on January 24, 1989,

to verify that the instruments were operable as required by TS. The

test was performed by qualified individuals who followed the

procedu re. All reviews and approvals were conducted and all data was

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within the required limits. The technicians were knowledgeable about

the function and operation of the test equipment. The NRC inspector

verified that all instruments were within calibration.

. SP 6.2.2.3.7, "HPCI Turbine High Exhaust Pressure Calibration and

Functional / Functional Test," Revision 10, dated December 23, 1987:

This procedure was performed on January 24, 1989, to verify

operability of the pressure switches. The pressure switches activate

to trip the high pressure coolant infection (HPCI) turbine in case of

discharge line blockage. The instrument and control (I&C)

technicians were cognizant of all precautions and limitations in the

procedure.

While observing the above surveillance tests, the NRC inspector noted that

the instrument shutoff valves were not sealed or locked in their normal

operating position. From plant tours the NRC inspector determined that

there are no instrument isolation valves scaled or locked at CNS. The NRC

inspector determined that Section VII.2.5 of the Updated Safety Analysis

Report (USAR) required instruments which sense reactor pressure and

reactor water level and input to the reactor protection system (RPS) to be

locked or sealed. The instruments are located on Local Racks 25-5

1 and 25-6 The failure to lock or seal the instrument shutoff valves for

the process instruments which input a signal to the RPS is contrary to

USAR commitments. The USAR states, in part, "The test signals can be

applied to the process type sensing instruments through calibration taps

which feed RpS channels. These calibration taps are located on local

panels in the reactor building. These panels, MPL 25-5 and MPL 25-6,

contain instrumentation for reactor pressure and water level. The test is

conducted as follows:

1. An instrument technician following instructions of authorized

personnel unlocks or cuts the seal on the instrument shutoff valves

to a specific instrument and shuts off the instrument line . . .

8. The calibration signal is then reduced to zero, the test is removed,

the calibration taps plugged, the sensors valved into service, and

the valves sealed or locked in their operating positions."

The failure to have instrument shutoff valves sealed or locked as

specified in the USAR constitutes a deviation to licensee commitments

(298/8901-01).

The ISI data on the "B" CS pump was within specifications. Adherence to

procedures was evident. All surveillance were performed in accordance

with applicable procedures. One deviation was identified in this area for

failure to seal or lock instrument isolation valves as committed to in the

USAR.

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5. Monthly Maintenance Observation (62703)

During the EDG No.1 operability surveillance test conducted on January 17,

1989, the maintenance department used a diagnostic electronic engine

analyzer (BETA Analyzer) on the diesel generators as part of a predictive

maintenance program. This analyzer test is not required by regulations;

however, the licensee uses this diagnostic tool to analyze individual

cylinder data to detennine potential problem areas. By taking measurements

of the peak firing pressures, cylinder exhaust pressures, and of vibration

in the fuel injector and head bolts, the licensee is able to trend and

identify abnormalities in the internals of the engine. Trending of the  !

data provides the licensee with information, so that corrective maintenance

is taken for minor problems and not for a failed EDG. The records generated

from the analyzer test consist of Polaroid snapshots of the oscilloscope

screen. The snapshots superimpose the vibration data and the cylinder l

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pressure so that analysis of the engine can be conducted. Use of the

snapshots provides more accurate information than taking a log of the

pertinent data and measurements. The NRC inspector determined that the

technicians operating the analyzer by the vendor had been trained on the

use of the instrument and interpretation of the data located on the

snapshots.

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On January 31, 1989, the NRC inspector observed the conduct of Preventive

, Maintenance (PM) Nos. 04712 and 04599. PM 04712 is performed annually and l

l is implemented by Procedure 7.3.37.1, "Meggering Environmentally Qualified

Reliance Motors," Revision 0, dated December 24, 1986. The electrical

technicians implemented PM 04599 in accordance with Procedure 7.3.37,

" Environmentally Qualified Reliance Motor Lubrication," Revision 0, dated

December 24, 1986. Lubrication of the fan coil motor is required every

3 years. The electrical technicians meggered Fan Coil Unit Motor FC-RF.

The test results were within specifications. The procedures were

followed, peer quality control was implemented, and the equipment was

properly tagged out. The technicians were knowledgeable and utilized

appropriate safety practices.

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The NRC inspector observed on January 31, 1989, the removal of the valve

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internals from the valve body of the "A" inboard MSIV. The maintenance

l was conducted to determine if the HSIV had failed since testing had been

l inconclusive. The maintenance was controlled and conducted in accordance

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with Maintenance Procedures 7.2.24 " Main Steam Valve Disassembly, Repair,

and Reassembly," Revision 10, dated September 17, 1987, and 7.2.24.1,

" Main Steam Isolation Valve Operator Maintenance and Repair," Revision 1,

dated October 15, 1987. The technicians were familiar with the

procedures. Proper As Low As Reasonably Achievable (ALARA) practices were

! implemented and proper safety precautions were followed.

' Maintenance personnel performed their activities in accordance with

applicable procedures and standard maintenance practices. Use of the

electronic engine analyzer as a tool in a predictive maintenance program

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for the EDGs is commendable in that it provides for safer and more reliable

sources of emergency power.

No violations or deviations were identified in this area.

6. Safety System Walkdown (71710)

The NRC inspectors began activities related to the walkdown of the plant

air system. Documents utilized during this review are listed in

Attachment 1 to this report. The drawings were compared to the lineups

contained in System Operating Procedure (SOP) 2.2.59, " Plant Air System,"

Revision 18, dated June 7, 1988. Minor discrepancies concerning valve

positions between the systen lineup sheets and the drawings were

l identified by the NRC inspectors. The NRC inspectors reviewed the Type 4

discrepancies, i.e., those where resolution by NPPD is necessary,

previously identified by Applied Power Associates (APA). During their

as-built walkdown of the plant air system, APA identified that

approximately 200 valves had been identified as installed in the plant

which were neither on the drawings nor on the lineup sheet. Many of the

valves had been added to the air system by replacing a single hose

connection with an "H" configuration that had four hose connections.

Other examples of the identified problems were: uncapped lines; unlabeled

l and mislabeled valves; lack of drawings for local instrument racks;

inaccurate system configurations; and discrepancies between the lineup,

l the drawing, and the field configuration. From review of the Type 4

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Problem Notification Sheets generated by APA, the hRC inspector concluded

that the walkdowns were very thorough,

Review of the problem resolution sheets indicate that the licensee had

evaluated the problems for safety significance and had determined

corrective actions. Examples of the resd utions included: capping the

lines found uncapped, hanging temporary valve labels on unlablea valves,

issuing work items to have mislabled valves corrected, issuing drawing

change notices (DCN) to correct inaccurate drawings, issuing DCNs to

document local instrument racks previously undocumented, correcting the

vahe lineups, and updating the equipment data file. Most discrepancies

had been resolved by the time of this review. Final resolution of the

problems identified with the plant air system is scheduled to be completed

by the end of 1989 or early 1990.

While the NRC inspectors identified several minor discrepancies between

the operating procedure and the system diagrams, these had previously been

identified during as-built system walkdowns. APA appeared to have been

very thorough in their as-built walkdown of the plant air system. The

licensee evaluated each Type 4 discrepancy for its impact on plant safety.

This activity will be continued in the next inspection period.

No violations or deviations were identified in this area.

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7. Exit Interview (30703)

An exit interview was conducted on February 6,1989, with licensee

representatives (identified in paragraph 1). During this interview, the

NRC inspectors reviewed the scope and findings of the inspection. Other

meetings between the NRC inspectors and licensee management were held

periodically during the inspection period to discuss identified concerns.

The licensee did not identify as proprietary any information provided to,

or reviewed by, the NRC inspectors.

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ATTACHMENT

The documents listed below were utilized during the system lineup

comparison to the drawings.

50P 2.2.59, " Plant Air System," Revision 18, dated June 7,1988

Burns and Roe, Inc (B&R) 2010, Sheet 1, " Flow Diagram-Instrument Air,

Control and Turbine BLDG"

B&R 2010, Sheet 2, " Flow Diagram-Instrument Air, Reactor BLDG"

B&R 2010, Sheet 3, " Flow Diagram-Service Air"

B&R 2010, Sheet 4, " Flow Diagram-Instrument Air, Radwaste and Augmented

Radwaste Buildings"

COSMODYNE 6000355, " Solenoid Rack Assy-Charcoal Tank Room, Augmented

Offgas(A0G) Room"

COSMODYNE 6000358, Sheet 1, " Solenoid Rack A Assy-Recombiner Room, A0G

System"

COSM0 DYNE 6001848, Sheet 1, " Solenoid Rack B Assy-Recombiner Room, A0G

System"

B&R IL-E-70-3, Sheet 115, " Reactor Building Local Instrument Rack LR-104"

B&R IL-E-70-3, Sheet 146, " Installation Details-Reactor Bldg. RWCU Sep.

Solenoid Rack LR-115"

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B&R IL-E-70-3, Sheet 46A, " Diagrammatic List of Primary Loading and Air

Supply Lines LR 12-4-130(A)"

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B&R IL-E-70-3, Sheet 46B, " Diagrammatic List of Primary Loading and Air

Supply Lines LR 12-4-130(B)"

B&R IL-E-70-3, Sheet 49, " Diagrammatic List of Primary Loading and Air

Supply Lines LR 12-4-131 A&B"

B&R IL-E-70-3, Sheet 144, " Installation Details-Radwaste Lab Drain

Solenoid Valve Rack LR-144"

B&R IL-E-70-3, Sheet 119, "Radwaste Building-Condensate Demin Local

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Instrument Rack LR-106"

B&R IL-E-70-3, Sheet 134, "Radwaste Building-Fuel Pool Filter Demin Local

Instrument Rack LR-110"

B&R IL-E-70-3, Sheet 142, " Installation Details-Radwaste Demin Solenoid

Valve Rack LR-113"

Delaval FD-3002CL, " Solenoid Valve Rack-Assorted"

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B&R IL-E-70-3, Sheet 48, " Diagrammatic List of Primary Loading and Air

Supply Lines Fuel Pool Cleanup Solenoid Valve Racks" l

B&R IL-E-70-3, Sheet 171B, " Installation Details-Floor Drain Demin i

Solenoid Valve Rack LR-135"

B&R IL-E-70-3, Sheet 123, " Installation Details-High Conductivity Process  !

Local Instrument Rack LR-109"

B&R IL-E-70-3, Sheet 172B, " Installation Details-Solenoid Valve

Rack LR-136"

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B&R IL-E-70-3, Sheet 155, " Steam Trap Stations Bypass Valves Control

Panel LR-120"

Honeywell, Inc. 1550-X300, " Piping Schematic IR-1A & IR-1B"

Honeywell, Inc. 1550-X301, " Piping-Instrument Rack IR-1C"

Honeywell, Inc. 1550-X102, " Piping-Instrument Rack IR-ID"

Honeywell, Inc. 1550-X103, " Piping-Local Instrument Rack IR-1E"

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