ML20206J596

Insp Repts 50-413/88-34 & 50-414/88-34 on 880926-1025. Violations Noted.Major Areas Inspected:Plant Operations, Surveillance Observation,Maint Observation & Review of Licensee Nonroutine Event Repts

ML20206J596
Person / Time
Site:	Catawba
Issue date:	11/15/1988
From:	Lesser M, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20206J564	List: ML20206J560 ML20206J582 ML20206J596
References
50-413-88-34, 50-414-88-34, NUDOCS 8811290049
Download: ML20206J596 (16)

See also: IR 05000413/1988034

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j gdtero UNITED STATES

" 'o NUCLEAR REGULATORY COMMIS$10N '

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y' o REGION il

101 MARitTTA STREET,N.W.

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8 2 ATLANTA, GEORGI A 30323

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Report Nos. 50-413/88-34 and 50-414/88-34

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Licensee: Duke Power Company

422 South Church Street

Charlotte, N.C. 28242

a Docket Nos.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52

' Facility Name: Catawba 1 and 2

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Inspection Conducted: September 26, 1988 - October 25, 1988

Inspectors

W. T. Ofd rs

fd'?/~/

/b) /// TW

Date/ Signed

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Inspectors * //Y/ // Sd[

"M. 5.'T. esser Fa te/ Signed

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Approved by: o . //-/ T-77

T. A. Peebles 3 SectioriT,hief Date Signed

Projects Branch 3

Division of Reactor Projects

SUMMARY

Scope: This routine, resident inspection was conducted on site inspecting in

the areas of review of plant operations; surveillance observation;

maintenance observation; review of licensee nonroutine event reports;

and followup of previously identified items; part 21 reports and

containment temperature instrumentation.

Results: In the areas inspected, the licensee's programs were observed to be

adequate. One weakness was identified in the area of valve position

limit switch setup for which corrective actions are ongoing. Two

violations were identified one for failure to initiate prompt

corrective action following discovery of a valve failure and the-

other with four examples involved procedural adherence or inadequacy.

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8911290049 081116

PDP

0 ADOCK 05000413

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

• H. B. Barron, Operations Superintendent

W. F. Beaver, Performance Engineer

W. H. Bradley, QA Surveillance

• R. N. Casler, Unit 1 Coordinator

R. H. Charest, Station Chemistry Supervisor

T. E. Crawford, Integrated Scheduling Superintendent

W. P. Deal Health Physics Supervisor

• R. M. Glover, Compliance Engineer

• T. P. Harrall, Design Engineering

F. N. Mack, Project Services Engineer

W. W. McCollough, Mechanical Maintenance Supervisor

W. R. McCollum, Station Services Superintendent

C. E. Muse, Unit 2 Coordinator

• T. B. Owen, Station Manager

G. T. Smith, Maintenance Superintendent

J. M. Stackley, I & E. Engineer

D. Tower, Shift Operating Engineer

• R. F. Wardell, Technical Services Superintendent

R. White, CSRG Chairman

J. W. W'111s, Senior QA Engineer, Operations

Other licensee employees contacted included technicians, operators,

mechanics, security force members, and office personnel.

NRC Resident Inspectors

• W. T. Orde.'s

• M. S. Lesser

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• Attended exit interview.

2. Unresolved Items

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An Unresolved item is a matter about which more information is required to

determine whether it is acceptable or may involve a violation. There were

three unresolved items identified in this report (paragraphs 3d, 5d and I

6b).

3. Plant Operations Review (71707 and 71710)

a. The inspectors reviewed plant operations throughout the reporting

period to verify conformance with regulatory requirements, Technical

Specifications (TS), and administrative controls. Control room logs,

danger tag logs, Technical Specification Action Item Log, and the

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removal and restoration log were routinely reviewed. Shift turnovers

were observed to verify that they were conducted in accordance with

approved procedures.

The inspectors verified by observation and interviews, that the

measures taken to assure physical protection of the facility met

current requirements. Areas inspected included the security

organization; the establishment and maintenance of gates, doors, and

isolation zones in the proper conditions; and that access control and

badging were proper and procedures followed.

In addition to the areas discussed above, the areas toured were

observed for fire prevention and protection activities. These

included such things as combustible material control, fire protection

systems and materials, and fire protection associated with

maintenance activities. The inspectors reviewed Problem

Investigation Reports to determine if the licensee was appropriately

documenting problems and implementing appropriate corrective actions.

b. Unit 1 Sumary

The unit started the reporting period at 100% power. On September 27

power was reduced to 20% to repair a packing leak on a Feedwater

Regulating Valve (CF-55). The unit returned to 100% power af ter

completion of the maintenance and operated thera for the remainder of

the inspection period,

c. Unit 2 Summary

The unit started the reporting period at 95% power. On September 28

a worker inadvertently secured the main generator Stator Cooling (KG)

pump which initiated a turbine runback. The ensuing feedwater

transient resulted in a steam generator high high level feedwater

isolation and a manual reactor trip from approximately 35% power.

The unit was started up on October 1 and gradually increased power to

100% by October 4. On October 12 power was reduced to 98% due to

recurring fouling of the feedwater flow orifice to the 2C steam

generator. On October 16 resin from a condensate polisher was

inadvertently pumped into the steam generators. The resulting high

sulfates and cation concentration required power level to be reduced

to 2% until the contamination could be cleaned up. The t: nit returned

to 98% power on October 19 and operated there for the remainder of

the inspection period.

d. On the afternoon of October 17, 1988 the resident inspector, during a

routine tour of the control room, noted in the Unit 2 Technical

Specification Action items Logbook (TSAIL) that both B diesel

generator starting air (VG) compressors had been taken out of service

at 7:30 a.n that morning. The inspector also noted that at 9:50 am

that morning, the 2A motor driven auxiliary feedwater pump was

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removed from service. The inspector, in discussions with the unit 2

operators, determined that the D/G was actually considered to be

operable because the accumulators (air tanks) were charged to their

normal pressure which is approximately 250 psig. This pressure, by

design, and as described in FSAR Section 9.5, is sufficient to ensure

adequate capacity for a minimum of five successful engine starts.

The inoperability of the VG compressors had been noted in the TSAll

for "tracking purposes" only.

The inspector was concerned about not having the compressors

operable. This concern was based, in part, on a previous observation

by the inspector of a recent 1A diesel run during which both VG

compressors ran continuously af ter the engine start for the entire

time the inspector was in the diesel room (approximately 35-40

minutes). This, coupled with the knowledge that the diesel employs a

pneumatic control system which must be operable for t'? diesel to run

and a recent related incident associated with the starting air system

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for the McGuire diesels prompted the inspector to expand his review.

In a review of the Removal and Restoration (R&R) under which the VG

compressors were removed from service, and discussions with

operations supervisory personnel, it was learned that both

compressors were remon.u from service to facilitate the installation

of a modification which would provide the VG air dryers with separate

power supplies. It was also learned that one of the compressors was

apparently returned to service at approximately 11:00 am that morning

after necessary wiring modifications had been made.

In an effort to determine if having both VG compressors inoperable

actually degraded the D/G, the inspector reviewed the FSAR and other

documents,

in FSAR, Section 8.3.1.1.3, the 0/G's are described as having air

storage capacity sufficient for a minimum of five successful engine

starts without the use of the air compressors. When the diesel

generator receives an automatic start signal from the diesel

generator load sequencer, starting air is admitted to the engine to

begin the starting process. If the engine has not attained at least

44% rated speed within 10 seconds after receiving the automatic start

signal, the diesel engine will continue to admit starting air until a

second start attempt occurs.

Sufficient starting air is available for two automatic start

attempts. This includes a first unsuccessful start attempt and a

second start attempt. If the diesel does not start on the second

automatic attempt and starting air pressure drops below 150 psig, the

diesel will cease trying to start automatically.

The starting air receiver tanks also supply air at reduced pressure

to the engine control instrumentation. Air enters the engine control

pa iel where it is filtored and a self-contained pressure regulator

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maintains constant pressure of 60 psi for the diesel automatic safety

shutdown system. The automatic safety shutdown system is made up cf

a network of vent on fault pneumatic devices which monitor the

engines parameters, tripping the engine when a recomended

temperature, pressure, overspeed, or vibration setpoint has been  :

exceeded. The control system trips the diesel by removing the air

from the pneumatic devices. Herein lies the inspectors concern  ;

relative tc 3e operability of the diesel with no makeup air '

available.

After review of the above mentioned documents, the inspector in

discussions with the licensee confirmed their belief that a D/G is '

operable with both VG compressors inoperable if the VG receiver tanks

are charged. Pending receipt of dccumentation to support the

licensee's contention, the matter of 0/G operability will be carried

as an Unresolved Item 413/88-34-02: 0/G Operability With Both VG

Compressors Inoperable.

During the above mentioned event analysis, the inspector reviewed

Operations Management Procedure (OMP) 2-29 which includes

instructions for the operating staff on support systems which are

required for operability of Technical Specification (TS) required

equipment. Page 36 of Attachment 3 to OMP 2-29, lists VG as required

to be operable to support the operability of the diesel generators.

Specifically, one VG air compressor and storage tank are required to

support each diesel. The procedure specifies that if a compressor l

and tank are not operable the operators are to provide an operable '

alternate source of compressed air or declare the diesel inoperable

and enter the TS action statement,

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When this was discussed with the licensee, operations management

stated that the intent of the requirement to have VG operable as a

support system was to support "long term operability". Operations

management stated what was intended by the statement in a column l

titled Discussion / Reference in OMP 2-29. The statement specifies , i

that "as long as sufficient pressure is in the tanks, support systems i

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are not needed; however, some controls on the diesel are supplied by

storage tanks; therefore, compressor (s) are required for long term

operability." bsing that logic, VG would not be required if the i

diesel was only required for a short time af ter being called upon to i

perform it's intended safety function. However, one cannot predict

how long the 0/G would be required to perform its safety function.

Therefore, one cannot predetemine that VG is not necessary to

support VG operability.

Assuming the provisions of OMP 2-29 would be employed as interpreteu

by operations management the procedural requirement (Station

Directive 3.1.14) associated with taking compensatory actions was not

performed in this case. Station Directive 3.1.14, Operability

Determination, specifies that when there is a requirement for

automatic actuation of a system, subsystem, train, component, or

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device to fulfill a specific safety function, the item shall be

declared inoperable upon loss of automatic capability.

The procedure goes on to say that in some situations manual operation

of the system, subsystem, train, component, or device may be

considered to replace the lost automatic capability. This would be

considered compensatory action replacing the lost automatic function

and would need to meet the following criteria:

1. A procedure or other written instruction is available to direct

the manual operation.

2. The individual designated to perform the function has been

trained / qualified.

3. The post accident environment in which the designated individual

must operate is acceptable, ,

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4. The response time assumptions of the accident analysis can be

met.

5. An individual can rcasonably perform the task (strength, -

accessibilit>>.

6. The sigal or indication which will signify the individual to

perform tne function has been clearly defined, as well as the

method through which it will (can) be connunicated during  ;

accident conditions.  ;

Compensatory measures taken are to be documented on Enclosure 3 to  !

The Station Ofrectory, Compensatury Actions To Maintain Operability. t

These actions were not performed.

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Given the foregoing, it appears that:

1) OMP 2-29 is inadequate in that the procedure is ambiguous

when specifying the operability of the VG system. The

procedure requires the components to be operable, yet

states they are required only for long term operability.

Huwever, "long term "is not defined. This was a point of

. confusion among the operators queried.

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2) Station Directive 3.1.14 was not followed as described

above.

The two cases above constitute two of four examples in this report of

inadequate or failure te follow procedures and are identified as a

/iolation of Technical Specification 6.8.1. (413,414/88-34-01)

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e. On the morning of October 15, 1988 the Catawba Unit 2 operating staff

was notified by secondary chemistry personnel that sample results

indicated that the unit was in Action Level 3. Action Level 3 is a

secondary chemistry condition described in part when samples reveal

sodium (Na) concentrations greater than 500 ppb (the normal

concentration is less than 20 ppb) or cation conductivity greater

than 7 micro mho/cm (the normal valve is less than 0.8 micro mho/cm).

> On the morning in question, cation conductivity was 45 in the B S/G

and 110 in the D S/G.

The concern with having secondary chemistry out of specification is

steam generator S/G tube corrosion which leads to concerns relative

to tube leaks or ruptures.

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Abnormal Procedure AP-0-A-5500-34, Secondary Chemistry Out of

Specification, specifies the actions to be taken to identy and ,

correct the cause of the chemistry problem and to minimize S/G

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corrosion. The procedure specifies the actions to be taken when in

Action Level 3. The procedure requires that the operator "Ensure

power level reduced to (less than) 2% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />." After having

been natified of the situation at approximately 6:15 a.m., the

operators began reducing load at 6:20 am,

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The inspectors noted through log book review, however, that reactor

, power was not reduced to less than 2% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by

the procedure. The unit was not at 2% power until about 11:50 am or

51/2 hours after notification.

The inspectors questioned the licensee as to why the unit was not

placed in the condition required by the procedure. The inspectors

were told that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> was not a realistic time within which to shut

the unit down in a controlled manner given the fact that unit 2 has

the 05 S/G level control problems. The inspectors asked why the

i procedure had not been changed to reflect a realistic time for unit

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shut down, or why the procedure in use on October 15, had not

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undergone a procedure change.

The licensee stated that the procedure had been under review for

rearly a year and they were awaiting information from the j

Westinghouse S/G owners group relative to the relaxation of the 4

hour requirement. The licensee also stated that a simple pen and ink

change (a temporary procedure change) to an AP is not normally

allow 2d and that a retype would have been required.

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The procedure, as written is inappropriate for the circumstance; it

requires action which according to the licensee would jeopardize a

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controlled unit shutdown and enuld result in unwanted safety system

challenges.

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Given that procedure, AP-0-A-5500-34, is inappropriate for the

circumstances it is considered inadequate and as such constitutes the

third of four examples ir this report of a failure to follow or

inadequate procedures and is violation of the requirements of

TS 6.8.1 (413,414/88-34-01)

4. Surveillance Observacion (61726)

a. During the inspection period, the inspector verified plant operations

were in compliance with various TS requirements. Typical of these

requirements were confirmation of compliance with the TS for reactor

coolant chemistry, refueling water tank, emergency power systems,

safety injection, emergency safeguards systems, control room

ventilation, and direct current electrical power sources. The

inspector verified that surveillance testing was performed in

accordance with the approved written procedures, test instrumentation

was calibrated, limiting conditions for operation were met,

appropriate removal and restoration of the affected equipment was

accomplished, test results met requirements and were reviewed by

personnel other than the individual directing the test, and that any

deficiencies identified during the testing were properly reviewed and

resolved by appropriate management personnel.

b. The inspectors witnessed or reviewed the following surveillances:

4296 SWR SSPS and Reactor Trip Breaker Train "A"

Test

PT/1/A/4330/028 DG 1A Operability Test

PT/1/A/4200/01T 1B CA Pump Head Verification

PT/1/A/4200/01T Containment Penetration Valve Injection

Water System Test

5. Maintenance Observations (62703)

a. Station maintenance activities of selected systems and components

were observed / reviewed to ascertain that they were conducted in

accordance with the requirements. The inspector verified liccasee

conformance to the requirements in the following areas of inspection:

the activities were accomplishet using approved procedures, and

functional testing and/or calibrations were performed prior to

returning components or systems to service; quality control records

were maintained; activities performed were accomplished by qualified

personnel; and materials used were properly certified. Work requests

were reviewed to determine status of outst6nding jobs and to assure

that priority is assigned to safety-related equipment maintenance

which may effect system performance.

l b. The inspectors witnessed or reviewed the following maintenance

activities:

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27050 OPS Inspect / Repair VC/YC Chiller 'B'

Tripping

41478 OPS Inspect / Repair MSIV

Failure to clo:e

6625 PRF Inspect / Repair NS pump 2B Breaker

Failure to Close

29118 OPS Replace Channel 11 Power Supply

c. On October 6, 1988 the licensee was conducting slave relay testing on

Unit 2 using PT/2/A/4200/09A, Auxiliary Safeguards Test Cabinet

Periodic Test. Section 12.38 tests the ability of the 2B Containment

Spray (NS) Pump to start on ESF signal. The prerequisites to the

test require the NS pump circuit breaker 2ETB8 to be racked to the

"test" position and the pump suction valve from the refueling water

storage tr' , 2NS-38, to be open. A test switch simulating an ESF

signal is .omentarily depressed and breaker 2ETB8 is verified to

close. On October 6, 1988 this section of the procedure was run and

the circui?. breaker failed to close. Technical Specifications for

Containment Spray automatic act%cion logic and activation relays

requir. 2 channels. If one ch,nnel is inoperable the unit is to be

placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. In this case the licensee

applied a Technical Specification Interpretation dated December 1,

1987 which states in part Nfailure of the latch device to latch

properly on an SSPS activation relay does not constitute a failure of

the activation channel, it does, however, render inoperable those

components the latch device actuates." Procedure PT/2/A/4200/09A is

written to test the actuation relays individually. The licensee was

able to immediately identify the inoperable component as the 2B NS

pump. The licensee applied TS 3.6.2 which requires the NS pump to be

operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the unit in Hot Standby in the

following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

Work Request 6625 PRF was written to investigate. The problem was

isolated to the interlock in the pump start circuitry associated with

2NS-3B being open. The interlock in part ensures that 2NS-38 is open

prior to pump start, making sure a source of water is available. The

interlock consists of one of six sets of contacts on the Rotork

actuator's "add on pack" (A0P). The A0P contacts are typically used

for permissives, interlocks, torque bypass contacts, or monitor

lights and are different from "primary switch" mechanism contacts,

which are used for torque switch operation and valve position

indicators.

During troubleshooting the technicians stroked the valve several

times and detennined that the A0P contacts did not actuate correctly

each time. The A0P had apparently been set up in a marginal fashion

such that tolerances allowed the contacts to correctly actuate upon

valve strmng in some random cases, but failed to actuate on others.

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Apparently the last time 2NS-3B had been opened, the primary switch

mechanism actuated correctly when the valve opened and deenergized

the motor actuator, however, the A0P contacts did not actuate and

failed to make up the interlock. IP/0/A/3820/09, Removal,

Replacement and Field Set up of Rotork Actuators, section 10.5.6

states "A0P switches that are intended to actuate as volve reaches

open end of travel shall be adjusted to actuate just prior to >

actuation of primary switch mechanism open limit switcles". A

similar requirement exists for switches that actuate upon valve ,

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closure. Clearly for the A0P contacts to function properly, they

must actuate prior to the primary switch mechanism contacts, however

there is no apparent reason to actuate "just prior" to the primary  :

switch mechanism contacts. The procedure ,1ves no consideration for

tolerances involved with the equioment and provides no amplifying

guidance as to what is meant by "just prior". The procedure appears

to er. courage the technician to set up the A0P as close as possible to

the primary switch mechanism and to leave no margin. Although the

procedure requires functional checkout of the contacts after setup,

tolerances may result in an A0P contact operating correctly after one

valve stroke, but not in the next. This is apparently what occurred

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with 2NS-3B.

The safety significance of the incorrectly set AOP is as follows:

The system automatically actuates upon a high high containment

pressure (Sp) ESF signal of 3.0 psig and isolates when pressure drops  !

to 0.3 psig. The incorrectly set A0P for 2NS-3B would have prevented t

a pump start if a Phase B Containment Isolation signal had been i

initiated manually. The pump would have started on an automatic Sp

signal or on a manual pump start as the interlock is not present in

these portions of the circuit.

At the inspect,rs request the licensee reviewed previous work

requests to compile a history of A0P related problems. The licensee

htermined that previous problens requiring A0P adjustments had

occurred on five occasions since early 1987; three involving valve

interlocks and two involving the failure of a monitor light.

On March 27, 1987 unit 2 was shutdown. On attempting to start ,

the Residual Heat Removal (ND) system, hcwever, valve 2ND-36B, '

28 N0 pump hot leg suction; failed to open because the interlock

from 2N1-1368 failed to actuate. Valve 2NI-136B allows ND to

supply flow to the suction of the Safety Injection pumps (NI)

during "piggy back" operation and is required to be shut prior

to opening 2ND-36B. The AOP for 2Nt-136B was adjusted to

correct the problem.

• On December 6, 1987 with unit 1 shutdown operators were unable

to open ' Q-27A, Refueling Water Storage Tank (FWST) Supply to

1A ND pop. The problem was isolated to the interlock from

1NI-185A, Containment Sump Supply to 1A ND pump. The interlock

ensures that both valves are not simultaneously opened. The A0P

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for 1NI-185A was adjusted to correct the problem. It had

recently been setup after MOVATS testing on November 9,1987.

On October 6, 198o the 2A NS pump breaker failed to close during

slave relay testing. The interlock requiring 2NS-32A, 2A NS

pump discharge valve, be shut prior to testing the pump had

failed, however, only the slave relay test circuitry was

affected. The AOP was adjusted to a.or"ect the problem, l.ater

that day the previously described problem accurred with the 2B

NS pump.

The licensee ini'ially felt the above probler.s to be isolated and

random, however. agreed that the setup procedure was inadequate and

should be revisH to ensure that in the future a margin exists

between A0P contact actuation and primary switch mechanism contact

actuation. Due to the inadequate setup procedure and history of

occurrences, the inspectors were concerned that the problem could

exist generically. After further discussions the licensee

prioritized a list of valves containing A0P's with safety related

interlocks and permissives. The list contains 25 valves on unit 1

and 26 on unit 2,13 of which on each unit are accessible during

power operations. The licensee is setting up a plan for inspection

, and adjustment as neces.ary. This is identified as Inspector

Followup Item 414/88-34-04: Testing and Adjustment of Rotork Add On

Pack Switches.

d. On the morning of October 11, 1988 at approximately 11:00 AM, the

inspector observed two Instrument and Electrical (IAE) technicians

replacing the Unit 1 protection channel 2, 24 VDC Backup power

supply.

The inspector reviewed work request OPS 29118 under which the work

was being performed. The inspector noted that the technicians had no

equipment specific electrical prints nor as built cabinet

in+.erconnection diagrams. Instead they were employing a general

troubleshooting procedure IP-0-A-3890-01, Controlling Procedure for

Troubleshooting and Corrective Maintenance and were referring to a

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Westinghouse Tech Manual.

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The inspector was concerned relative to the accuracy of the

Westinghouse manual. This issue is discu> sed below.

At approximately 1:30 pm that same day the inspector returned to

review the status of the work. The inspector noted that the

technicians were t. hen performing wor; without the above mentioned

work request, with no procedure, and no prints. The inspector asked

to review the work request and proNdure and was told that the work

package had been lef t back in the office. At this point, work

stopped while the technicians retrieved the *:auired documents.

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The technicians returned with the work package, and continued to use

the procedure throughout the remainder of the work observed.

A number of concerns were identified with the above evolutions. The

first was the performance of work without the benefit of a procedure,

prints, or work request.

Technical Specifications 6.8.1 requires that written procedures shall

established, implemented, and maintained covering the activities

referenced in Appendix A of Regulatory Guide 1.33, Revision 2,

February, 1978. One of the activities referenced is the performance

of maintenance that can effect the perforraance of safety related  ;

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equipment. The work being performed by the two technicians was on

safety related equipment that can affect the performance of other

safety related equipment.

The failure of the technicians to employ a procedure during the above

mentioned work is a fourth example in this report of a Violation of

the requirements of TS 6.8.1. (413,414/88-34-01)

Another area of concern, is the fact that on the af ternoon of

October 11, the technicians did not have the work request in their

possession. The work request is considered to be a "general"

procedure designed to control maintenance, repair and replacement of

equi pment. A third area of concern is the lack of equipment

specific, as built electrical prints.

The inspector has not completed his review of the failure to have the

work request at the job site, and the lack of electrical prints.

Pending the completion of that review, these areas will be carried as

an Unresolved Item 413/88-34-03: Lack of Electrical Drawings for

Channel II Power Supply.

6. Review of Licensee Non Routine Event Reports (92700)

a. The below listed Licensee Event Reports (LER) were reviewed to

determine if the information provided met NRC requirements. The

determination included: adequacy of description, verificacion of

compliance with Technical Specifications and regulator / requirements,

corrective action taken, existence of pot (ntial geacric problems,

reporting requirements satisfied, and the 21ative safety

tignificance of each event. Additional inplant reviews and

d,scussion with plant per;onnel, as appropriate, were conducted for

those reports indicateu sy an (*). The following LCRs are closed:

413/86-;4 Rev 1. Two InaJvertent Containment Purge Trips Oue

to Unknown Cause and Procedural Deficiency.

• 413/88-22 Technical Soecification Violation Due to

Failure to Retast a Containmer.t Isolation

Valve.

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• 414/87-9,1 Rev 1. Reactor Trip Resulting From a Condensate ,

Transient Oue to Unknown Cause.  :

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414/87-24 Main Feedwater Isolation and Auxiliary Feed

Water Pump Auto Start due to Steam Generator r

Overfill Caused by Management "-ficiency.  !

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• 414/88-13 Rev 1. Feedwater Isolation Caused by Steam

Steam Generator High Level Due to Valve

Failure and a Personnel Error.

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414/88-14 Rev 2. Auxiliary Feedwater Auto Start Due to Loss

of Main Feedwater Pump Turbine Condenser

Vacuum.

b. On March 9,1988 with anit 2 in Mode 5, stean generators were being

As the level the 2A steam generator

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, filled for flushing evolutions. t

approached the high high level trip setpoint, the operator attempted

to close 2CA-62A, Auxiliary Feedwater (CA) Isolation from 2A Motor ,

Oriven CA Puhlp. The operator also tripped the 2A Motor Driven CA i

Pump, however, was unable to prevent an ESF actuation. The event was i

l reported in Licensee Event Report (LER) 414/88-13. On March 28,  !.

during the licensee's investigation of the incidcnt, it was

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determined that 2CA-62A failed to close during the event and Problem

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Investigation Report (PIR) 2-C88-0143 was written. The unit was in 7

Mode 1 at the time. The valve had apparently failed to close under a t

high differential pressure (dp) d e to the existing CA flow to the 2A l

Steam Generator. When the 2A Mowr Driven CA pump was secured and *

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the (dp) removed, 2CA-62A fully closed as the operator continued to

press the control board switch.Section II of the PIR requires an ,

evaluation of the condition for reportability and operability. The ;

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evaluation was not performed until April 5 and although 2CA-62A had  !

failed to close under dp conditions, it concluded that t6e valve was

operable. Proposed resolution of the problem recomended a M0 VATS l

< test of the valve to check torque switch settings and part. meters i

l against baseline data. 2CA-62A uses a Rotork motor actuator and itt l

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safety function is to close within 20 seconds after operator action

to isolate the 2A steam generator from the 2A CA pump in the event of  !

I a ruptured steam generator or steam line. On April 20, Design .

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! Engineering determined that the failure of 2CA-62A to close was not

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an operability concern. The was based on calculations demonstrating i

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that a condition resulting in insufficient CA flow to steam c

generators would not result, nor would additional energy into l

containment be significant. '

! On April 27 the unit was in Mode 5 and 2CA-62A was M0 VATS tested and

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all settings were detennined to be correct. On April 28 the valve ,

was tested under full dp conditions ind it failed to close. The  !

toraue switch setting was adjusted from 41/4 to 4 3/8 and the valve

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was tested satisfactorily.

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1 The resident inspectors were concerned with the following: The

licensee failed to declare 2CA-62A inoperable on March 28 after

discovering that it has not closed upon demand. The licensee was

unable to produce any tests which demonstrated 2CA-62A operable

between March 9 and the failure that occurred on April 28.

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10 CFR 50 Appendix B criterion XVI requires in part that measures be

established to ensure conditions adverse to quality such as failures

and malfunctions are promptly identified and corrected. In this case

established measur(s were inadequate and this is identified as a

violation of criterion XVI Appendix B, violation 414/88-34-02:

Failure to take Prompt Corrective Action to Ensure Operability of

2CA-62.

1 aview of the event determined that 2CA-62A failed to close even

I chough the torque switch settings were originally correctly set to

design calculations which specify required thrust output based upon

dp and on assumed packing load (a function of valve stem size). The

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inspectors were concerned with the adequacy of the calculations on

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the performance of the actuator and its generic implications. A

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review of design calculations showed a total required thrust of 12112

lbs. consisting of a dp component of 1071 lbs. and a packing load

component of 1375 lbs. A tolerance of -v, + 15% is specified.

Initial MOVATS settings established on December 4,1987 with closed

4 torque switch setting at 4 1/4 resulted in 13810 lbs thrust. Testing

' performed on April 28 resulted in 13100 lbs thrust. The question

that remains to be answered is why the valve failed with the original

i torque switch settings. The licensee suspects a higher drag

l resistance coming from the valve internals and intends to open and

inspect the valve at the next available opportunity. The licenso

e additionally intends to validate its design calculations by

l performing bench testing of valves under maximum dp conditions. This

! is identified as Unresolved item 414/88-34-03: Thrust Performance of

i Rotork Actuator for 2CA-62A, pending comnletion of testing and

{

inspection of 2CA-62A.

7. Follow-up on Previous Inspection Findin5s (92701 and 92702)

i a. (Closed) Violation 413,414/88-25-01: Failed to maintain Two Operable

1 Channels of \alve Position Indication for PORY Block Valves. The

! licensee responded to the violation in correspondence dated

! September 16, 1988. TS amendments were issued October 6,1988 to

. require one operable channel of position indicator per valve. Based

l on this the item is closed.

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b. (Closed) Inspector Followup Item 413,414/88-19-01: Clarification of

I the EAL addressing loss of an Engineered Safety Feature (EST). The

! licensee revised enclosure 4.1 of RP/0/A/5000;1, Classificttion of

l Emergency, to clarify the ambiguity associated when an unusual event

j will be declared upon loss of an ESF. The revision requires a

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Notificuion of Unusual Event (NOVE) upon loss of an ESF function or

actuation system requiring a power reduction to mc<'e 3 by Technical

Specifications. The NOUE will be declared at the point a decision is

made to reduce power with the intent to enter mode 3. Based on this

the ite" is closed.

8. 10 CFR Part 21 Inspection (36100)

(Closed) Part 21-86-03: Contrometics Actuator with Emergency Override

Operator with Jackscrew Handwheel Units May Suffer Wearing / Fouling of

Threads in Actuator End Caps. The licensee determined that the subject

dampers are installed in the Auxiliary Building (VA) and Fuel Pool (VF)

Ventilation Systems, however, none of the actuators are equipped with the

emergency override jackscrew / handwheel. This determination was documented

in an August 18, 1988 memo to N. A. Rutherford, Jr. from T. F. Wyke and

J. F. Reed. This item is, therefore, closed.

9. Information of High Temperature Inside Containment (TI 2515/98)

The objective of this inspection was to review temperatures and

ventilation inside containment to determine if high temperatures are a i

plant specific problem. The inspector met with design engineering staff

members on September 8 to review ventilation drawings, temperature

history, detector locations and environmental qualification considera-

tions.

The Containment Ventilation System (VV) i, divided into the lower

Compartnent Subsystem consisting of 4 ?.ir handling units and the upper

compartment subsystem, also with 4 units. Technical Specification 3.6.1.5

requires the upper containment average temperature be maintained between

75 and 100F and the Iowar containment be maintained between 100 and 120F

during power operations.

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One temperature detector is located at the suction of each of the 4 air

handling units in both upper and lower containment. The compartment's

temperature is verified daily by computing the average of the detectort'

readings associated with the operating air handling units.

The licensee recorded temperature results at various other points in tha

containment during portions of 1986 and 1987, including high and low

pc ints Of the pressurizer and steam generator cavities. The resu'ts for

different months of the ycar were sempled and reviewed by the inspectors.

Typically, readings were within the limits with the exception of the steam

generator cavities. In this portion of the lower containment,

I temperatures typically ranged from 120 to 150'F.

The licensee uses 120*F as the basis for calculating the remaining life

time of envircnmentally goalified equipment. No equipment of this type is

located in the steam generator cavities. Hydraulic snubbers in this area

(and mechanical snubbers elsewhere) are rated for 285'F.

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Most of the environmentally qualified equipment is located in lower

containment or the pipe chase area. Tha licensee was unable to provide

temperature data for the pi This area, however, is ventilated

with 4150 CFM (design value)pe chase.fans.

by booster

Based upon this review, stagnant areas do net appear to be a significant

! problem and the sensors used to verify containment temperature are

representacive of the average temperature.

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10. Exit Interview

The ir,spection scope and findings were summarized on October 26, 1988,  ;

with those persons indicated in paragraph 1. The inspector described the

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areas inspected and discussed in detail the inspection findings listed  !

l below. No dissenting coments were res.eived from the licensee. The '

i licensee did not identify as proprietary any of the materials provided to

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or reviewed by the inspectors during this inspection. -

Item Number Description and Reference.

413,414/88-34-01 Violation - Failure / Inadequate

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Procedure, four examples (para 3d, 3e i

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and 5d)

413/88-34-02 Unresolved Item - Diesel Generator

with VG Compressors t

Operability

Inoperable (para 3d)

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414/88-34-02 Violation Failure to Take Prompt t

Corrective Action to Ensure Operability t

of 2CA-62 (para 6b) [

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i 413/88 34-03 Unresolved Item - Lack of Electrical

Drawings for Channel II Power Supply l

(para 5d)

414/88-3/ 03 Unresolved item - Thrust Performance of

Rotork Actuator for 2CA-62 (pr.ra 6b)  ;

414/88-34-04 Inspector Followup Item - Testing and

Adjustment of Rotork Add on Pack

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