ML20214A385

Insp Repts 50-369/87-12 & 50-370/87-12 on 870321-0424. Violations Noted:Failure to Follow Procedure Pertaining to Auxiliary Feedwater Operational Readiness Valve Lineup

ML20214A385
Person / Time
Site:	Mcguire, McGuire
Issue date:	04/30/1987
From:	Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20214A372	List: IR 05000369/1987012 ML20214A369 ML20214A375 ML20214A385
References
50-369-87-12, 50-370-87-12, NUDOCS 8705190432
Download: ML20214A385 (8)

See also: IR 05000369/1987012

Text

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UNITED STATES

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-Report Nos.: 50-369/87-12 and 50-370/87-12

Licensee: Duke Power Company

422 South Church Street-

Charlotte, NC 28242

Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17

Facility Name: McGuire 1 and 2

Inspection Conduct : , 1987 - April 24, 1987

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Inspectors: /

W. Orders,

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r' esident Inspec or

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Tate Signed

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5 Tiuenther, Resident Inspefor Date $igned

Approved by: [] /b

T. A. Peebles, Se'ction Chief

Y[30/87

Date Signed

Division of Reactor Projects

SUMMARY

Scope: This routine unannounced inspection involved the areas of operations

safety verification, surveillance testing, and maintenance activities.

Results: Of the areas inspected, one violation was identified: Failure to

follow procedure pertaining to Auxiliary Feedwater operational readiness valve

line-up.

8705190432 870430

{DR ADOCK 05000369

PDR

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

• T. McConnell, Plant Manager

• B. Travis, Superintendent of Operations

D. Rains, Superintendent of Maintenance

• B. Hamilton, Superintendent of Technical Services

• N. McCraw, Compliance Engineer

• M. Sample, Superintendent of Integrated Scheduling

• N. Atherton, Compliance

Other licensee employees contacted included construction craftsmen,

technicians, operators, mechanics, security force members, and office

personnel.

• Attended exit interview

2. Exit Interview

The inspection scope and findings were summarized on April 24, 1987 with

those persons indicated in paragraph 1 above. One violation concerning

failure to follow procedure pertaining to the operation of auxiliary

feedwater was discussed. The licensee did not identify as proprietary any

of the information reviewed by the inspectors during the course of their

inspection.

3. Unresolved Items

An unresolved item (UNR) is a matter about which rr. ore information is

required to determine whether it is acceptable or may involve a violation

or deviation. No unresolved items were identified during this report.

4. Plant Operations

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The inspection staff reviewed plant operations during the report period,

to verify conformance with applicable regulatory requirements. Control

room logs, shift supervisors' logs, shift turnover records and equipment

removal and restoration records were routinely perused. Interviews were

conducted with plant operations, maintenance, chemistry, health physics,

and performance personnel.

Activities within the control room were monitored during shifts and at

shift changes. Actions and/or activities observed were conducted as

prescribed in applicable station administrative directives. The

complement of licensed personnel on each shift met or exceeded the minimum

required by Technical Specifications.

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Plant tours taken during the reporting period included, but were not

limited to, the turbine buildings, auxiliary building, units 1 and 2

electrical equipment rooms, units 1 and 2 cable spreading rooms, and the

station yard zone inside the protected area.

During the plant tours, ongoing activities, housekeeping, security,

equipment status and radiation control practices were observed.

Unit 1 Operations

Unit 1 operated at 100 percent power from the beginning of the report

period until 10:15 a.m. on April 14, 1987 when the unit experienced a

reactor trip. Instrumentation and Electrical (IAE) personnel had just

completed IP/1/A/3008/10, the " Turbine Auto Stop Oil Pressure Calibration"

procedure, and had Operations perform a functi_onal verification of the

pressure switches. This involved depressing an auto-stop oil (AS0) test

switch on the digital electro hydraulic (DEH) control panel in the control

room for each pressure switch that had undergone calibration. This

actuates a 3-way valve which isolates the pressure switch from the ASO

header and vents the switch to a drain tank to simulate a loss of ASO

pressure. When the pushbutton was released the 3-way valve repositioned

to refill and pressurize the switch and line thereby causing a momentary

drop in sensed pressure sufficient to actuate a second pressure switch and

satisfy the two out-of-three reactor trip logic. The licensee was able to

duplicate the situation during post-trip testing and has initiated action

to revise the surveillance procedure to prevent recurrence.

The licensee also determined that the procedure had never been performed

on a unit at power before, but there was no reason to suspect that an A50

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hydraulic transient sufficient to cause a reactor trip might occur.

All systems appeared to function normally during the trip. Unit restart

was delayed for a period of time, however, until periodic maintenance on

the "B" train of control room ventilation and chill water could be

completed to clear the made change restrictions of Technical Specification 3.0.4. A reactor startup began at about 11:00 a.m. the following morning,

with the unit entering mode 1 at 1:31 p.m. that afternoon. The unit

completed the report period at full power.

A potential concern regarding the estimated critical position (ECP)

calculation came to light during the above reactor startup. The ECP had

been calculated for a reactor startup time approximately one hour earlier

than the actual time of criticality. Criticality was anticipated at 82

steps on control bank D, with a " window" of plus or minus 500 PCM (percent

milli-rho). Criticality was actually achieved at Step 84 on control bank

C, which placed it above the rod insertion limit required by the Technical

Specifications, but below the ECP window. Since the reactor had tripped

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from a 100 percent equilibrium xenon condition approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

earlier, the rapid decay of xenon (from the post-trip peak) during the

hour-long startup delay accounted for a significant portion of the error

in the ECP. The licensee's startup procedures currently authorize an ECP

to be used for up to four hours after the estimated critical time, but the

possibility of shortening that time for fast recovery startups is being

evaluated. The licensee's reactor group is also evaluating the other

sources of error contributing to the poor estimate of April 16. These

issues will be tracked as an Inspectoc Followup Item (369,370/87-12-01).

A Notification of Unusual Event (N0UE) affecting both units was declared

at 7:20 a.m. on April 16, when it was discovered that the plant's

meteorological instrumentation was inoperable. Selected instrumentation

had been declared inoperable for maintenance on April 14. The 7-day

technical specification limiting condition for operation action statement

did not expire until April 21. Since this equipment was already

inoperable the operators did not immediately recognize the fact that the

operating instruments had also ceased to function during a severe

electrical storm at about 3:00 p.m. on April 15. The licensee replaced

the damaged meteorological instruments and terminated the NOUE at

7:04 p.m. on April 16.

Unit 2 Operations

Unit 2 operated at essentially full power for the entire reporting period.

It was unaffected by the Unit 1 trip of April 15, but was subject to the

NOUE of April 16 as discussed above.

5. Surveillance Testing

Selected surveillance tests were analyzed and/or witnessed by the

inspector to ascertain procedural and performance adequacy and conformance

with applicable Technical Specifications.

Selected tests were witnessed to ascertain that current written approved

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

calibrated, that test prerequisites were met, that system restoration was

completed and test results were adequate.

Detailed below are selected tests which were either reviewed and/or

witnessed:

PT/1/A/4601/04 RPS Channel 4

PT/0/A/4600/14C Source Range N-31,N-32 ,

PT/1/A/4601/01 RPS Channel 2 '

PT/1/A/4208/03A NS HX Test .

PT/1/A/4403/01B RN Train B l

PT/1/A/4206/01A NI Train A

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PT/1/A/4451/018 YC Train B

TT/0/A/9100/187 DG Halon

PT/1/A/4450/06A VX Train A

PT/1/A/4250/04G Turbine Trip / Reactor Trip

PT/1/A/4403/07 RN Train A

PT/2/A/4252/01B CA Train B

. PT/2/A/4252/01A CA Train A

' PT/2/A/4208/01A NS Train A

PT/2/A/4208/01B NS Train B

PT/2/A/4209/01A NV Train A

PT/2/A/4206/01B NI Train B

PT/2/A/4252/01 CA Turbine Driven

6. Maintenance Observations

Routine maintenance activities were reviewed and/or witnessed by the

resident inspection staff to ascertain procedural and performance adequacy

and conformance with applicable Technical Specifications.

The selected activities witnessed were examined to ascertain that, where

applicable, current written approved procedures were available and in use,

that prerequisites were met, that equipment restoration was completed and

maintenance results were adequate.

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a. Halon System Maintenance

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Each McGuire unit is equipped with two emergency diesel generators

(EDGs) to supply standby power for safe unit shutdown in the event of

a loss of offsite power. These EDGs are protected by a halon fire

suppression system consisting of two eight-cylinder banks (main and

reserve) for each unit. Either bank can be selected for standby

operation by means of a local selector switch. The selected bank is

actuated by either an automatic signal from the fire protection

system or by a manual pull lever on that bank's pilot cylinder. The

automatic actuation signal opens a solenoid pilot valve which admits

nitrogen from a small pilot control cylinder to the pilot cylinder's

manual pneumatic actuator. This actuates the pilot cylinder which

then supplies the additional gas pressure needed to actuate the

remaining seven slave cylinders in the bank.

While performing a performance test on February 18, 1987, Operations

personnel discovered that the manual pneumatic actuator on the Unit 2

main bank pilot cylinder did not operate properly. The reserve bank

functioned properly and was placed in service, and a work request was

initiated to repair the defective actuator. On March 11, 1987,

Maintenance personnel performed the " Diesel Generator Halon Cylinder

Pressure and Weight Test", MP/0/A/7400/49 on the Unit 2 main and

reserve banks. This involved removing the manual pneumatic actuator

and its flexible connection tubing from the pilot cylinder so that

the cylinder could be weighed.

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On March 17, 1987, Instrument and Electrical personnel began work on

the Unit 2 main bank actuator and discovered that the reason for its

" failure" on February 18 was that the actuator had been incorrectly

installed. The flexible tubing which connects the "A" and "B" ports

of the manual pneumatic actuator assembly to the actuation and slave

pilot manifolds were found reversed. The same condition was found to

exist on the Unit 2 reserve bank pilot cylinder suggesting that those

connections had probably been reversed during the performance of

MP/0/A/7400/49 on March 11.

The Unit 1 EDG halon fire suppression system was also inspected. The

main bank, which happened to be in service at the time, was found to

have the same problem as the Unit 2 system. The reserve bank,

however, was properly connected and was placed in service.

When the nature of the deficiency was understood, the licensee took

prompt action to restore the degradcd halon systems to their design

configuration and to correct the cause of the maintenance error to

prevent recurrence. Furthermore, on April 11, 1987, the licensee

conducted a special test of the EDG halon system to determine whether

the incorrectly configured manual pneumatic actuator assemblies had

rendered the systems inoperable. The Unit 1 reserve bank was placed

in the as-found (incorrect) condition and actuated in both the

automatic and manual modes. Five of the eight cylinders actuated in

the automatic mode and only one cylinder (the pilot) actuated in the

manual mode. These results indicate a definite degradation in system

performance while incorrectly configured, however, the licensee's

design organization is continuing to evaluate the results to

determine whether minimum required fire suppression capability

(operability) was maintained.

The failure of MP/0/A/7400/49 to ensure the proper reassembly of EDG

halon system pilot cylinder actuator assemblies on three occasions

clearly illustrates an inadequacy in that MP and, as such,

constitutes a violation of Technical Specification 6.8.1. As

permitted by Appendix C to 10 CFR 2, however, no Notice of Violation

is proposed and the incident is classified as a Licensee Identified

Violation (LIV 369,370/87-12-02).

b. Fire Suppression System Maintenance

The McGuire Nuclear Station fire suppression water system (RF)

consists of three motor-driven fire suppression pumps (A, B and C)

capable of taking suction from Lake Norman and transferring water

through an associated distribution system. The A and B pumps are

located in pits at the intake structure and are cooled by

thermostatically controlled air handling units (AHUs) mounted in

removable pit covers. Two pumps (A and C or B and C) are required to

be operable to satisfy Technical Specification requirements.

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On February 21, 1987, the motor on the B fire pump failed,

necessitating its removal and shipment to the vendor for repair. The

associated AHU was removed to permit the pump motor to be removed

from its pit and its electrical leads were individually taped and

tied out of the way.

On April 6, while reinstalling the B RF pump motor and its associated

AHU, an Instrument and Electrical (IAE) technician experienced a

"near miss" when, while pulling the AHU electrical leads through

their conduit, the insulating tape abraded and an electrical flash

occurred.

The licensee's investigation of the incident is on going, however, it

has been concluded that power to the AHU was never isolated by

opening the associated circuit breaker as required by the licensee's

Station Directive (No. 3.1.19), " Safety Tags, Lock-Outs , and

Delineation Tags". The licensee is attempting to determine whether

this incident represents an isolated instance of procedural

noncompliance or a more serious deficiency in the tagging program.

The Institute of Nuclear Power Operations (INP0) also reviewed the

incident during its recent evaluation of the McGuire facility and,

according to licensee management, intends to include it as a finding

in the Operations area. Although this incident represents a

violation of the station's tagout procedure and, therefore, Technical

Specification 6.8.1, no Notice of Violation is proposed at this time

pursuant to the memorandum of understanding between the NRC and INP0.

This item will, however, be carried as an Inspector Followup Item

(IFI-369,370/87-12-03).

7. Auxiliary Feedwater (CA) System Walkdown

Accessible portions of the Unit 1 CA System were walked down during the

inspection period to verify proper standby alignment in accordance with

OP/1/A/6250/02, " Auxiliary Feedwater System". Some material deficiencies

were detected (missing valve handle, loose packing gland retainer, missing

vent pipe cap) and reported to the licensee for correction. Subsequent

inspection revealed that the identified deficiencies had been remedied.

On April 8,1987, the inspector identified two valves on Enclosure 4.5,

the valve checklist, of OP/1/A/6250/02 that were in other than their

specified positions. Valves ICA-153 and 1CA-154 isolate CA storage tank

overflow to the Unit 1 and Unit 2 condensate storage tanks, respectively.

In a normal standby configuration, both the makeup to and the overflow

from the CA storage tank are aligned to Unit 1 (i.e. , ICA-153 is open and

1CA-154 is closed).

Upon finding the apparent misalignment the inspector consulted the

Operations Shift Supervisor to obtain verification that the valves were,

indeed, out of their normal positions and to determine whether the out of

normal operating condition was justified.

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OP/0/A/6100/09, " Removal and Restoration (R&R) of Station Equipment", is

normally used to provide the o)erators with an up to date status of all

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out of normal operating conditions by maintaining an R&R checklist in the

i control room until the equipment is returned to normal service. The

on-duty SS was unable to find an active R&R checklist to document the out

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of normal CA alignment and referred the problem to another Operations

staff member for resolution.

Further discussions with the Operations staff on April 9 confirmed that no

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R&R checklist had been completed to cover the deviation from the normal CA

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alignment. They speculated that the CA storage tank makeup and overflow

had been transferred from Unit 1 to Unit 2 on February 17 when a leaking

plant heating converter caused the Unit 1 secondary system sodium

) concentration to go out of specification (as documented in NRC Inspection

Report 369,370/87-05),

i Although the actual alignment of the CA storage tank to.either Unit 1 or 2

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is of minimal significance, the fact that the Operations Staff failed to

) maintain an accurate status of an out of normal operating condition as

i required by the R&R procedure is evaluated as an apparent violation of

l Technical Specification 6.8.1 (369/87-12-04).

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