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Insp Repts 50-369/88-23 & 50-370/88-23 on 880723-0819.One Violation Noted.Major Areas Inspected:Operations Safety Verification,Surveillance Testing,Maint Activities & Followup on Previous Insp Findings
	ML20154F991
Person / Time
Site:	Mcguire, McGuire
Issue date:	09/06/1988
From:	Croteau R, David Nelson, William Orders, Peebles T; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20154F977	List: ML20154F974; ML20154F980; ML20154F991;
References
	50-369-88-23, 50-370-88-23, NUDOCS 8809200209
	Download: ML20154F991 (9)
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a UNITED STATES

g .g NUCLEAR REGULATORY COMMISSION

o * REGION ll

101 MARIETTA ST., N.W.

e,,,, ATLANTA. GEORGtA 30323

Report Nos.: 50-369/88-23 and 50-370/88-23

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 Wame: McGuire 1 and 2

Inspection Conducted: July 23, 1988 - August 19, 1988

Inspectors:. FA(7//. It/ __ 9 jf[ i

ent Inspector Mat (d Signed

N. 0~rders,jpeji r Rep

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'D. Nels(n R'Widentppbetor 4att Signed

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" R. 'Croteau, Resident Inspector

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Approved by: I I ///>

T. A. Pe6bres, S~6ction Chief

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Date

(i.ied

Division of Reactor Projects

SUMMARY

Scope: This routine unannounced inspection involved the areas of operations

safety verification, surveillance testing, maintenance activities,

and follow-up on previous inspection findings.

Results: In the areas inspected, one violation for failure to follow procedure

and for an inadequate procedure was identified (see paragraphs 4 and

8.) Two unresolved items were identified: one for followup on

operators being unaware of the implementation of a modification which

lad to an ESF Actuation (paragraph 9) and one for followup on the

Problem Investigation Report process (paragraph 4).

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

J. Boyle, Superintendent of Integrated Scheduling

B. Hamilton, Superintendent of Technical Services

S. LeRoy, Licensing, General Office

T. McConnell, Plant Manager

W. Reeside, Operatiens Engineer

M. Sample, Superintendent of Maintenance

R. Sharp, Compliance Engineer

J. Snyder, Performance Engineer

B. Travis, Superintendent of Operations

R. White, IAE Engineer

Other licensee employees contacted included construction craftsment

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

personnel.

Attended exit interview

2. Unresolved Items

An un esolved item (UNR) is a matter about which more information is

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

or deviation. Two unraceived items were identified in this report and are

discussed in paragraphs 4 sad 9.

3. Plant Operations (71707, 71710)

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, msintenance, chemistry, health physics,

and performance personnel.

Activities within the control room were monitored during shif ts 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.

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

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limited to, the turbine buildings, the auxiliary bui; ding, Units 1 and 2

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

station yard zone inside the protected area.

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

equipment: status and radiation control practices were observed,

a. Unit l' Operations

Unit 1 operated at approximately 100 percent power with the exception

of a turbine runback to 97 percent power on August 8, 1988, at

12:35 a.m.. Instrumentation and Electrical (IAE) personnel had

placed channel 4 of the delta T instrument in test when the C loop

delta T momentarily reached the overpower delta T set point. C loop

delta T has been reading higher than normal due to a problem with the

C loop cold leg temperature RTD, which is reading low.

On August 19, 1988, while at 100 percent power, a card in the D steam

generator water level control system failed and started to burn.

Operators took manual control of the feedwater regulating valve on

the D steam generator and recovered water level. The card fire was

extinguished, however, an adjacent card controlling the feedwater

regulating valve bypass valve, the card reader, and other wiring in

the area were ' damaged. At the end of the inspection period the

feedwater regulating valve to the D steam generator was being

controlled in manual and the bypass valve was shut. Rapid operator

response in this case prevented a reactor trip. The unit remained at

100 percent power.

b. Unit 2 Operations

On July 24, 1988, two ESF actuations occurred while in Mode 3

involving feedwater isolation (see paragraph 9 for details). Unit 2

was critical on July 26,1988, at 7:00 a.m. following a refueling

outage which started on May 27, 1988. The unit reached full power on

July 31,1988 at 3:40 p.m. At 7:20 p.m. on July 31, 1988, the unit

was manually tripped from 100 percent power due to decreasing level

in the 2A steam generator (S/G). A worker in the turbine building

dropped a fan damaging a cable to a solenoid controlling air to the

2A S/G feedwater regulating valve 2CF-32. The loss of air caused

2CF-32 to shut isolating flow to the A steam generator. The cable

was repaired and the unit was on line at 10:26 a.m. on August 1,

1988. On August 5, 1988, power was reduced to correct a high

vibration problem on the turbire generator number 11 bearing. The

unit was taken off line but reactor power was maintained at

approximately 10 percent. The unit returned to full power operation

on August 7, 1988.

No violations or deviations were identified.

4. Surveillance Testing (61726)

Selected surveillance tests were analyzed and/or witnessed by the

inspector to ascertain procedural and performance adequacy and conformance

with applicable Technical Specifications.

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Selected tests were witnessed to ascertain that current written approved

procedures were available ar'. in use, that test equipment in use was

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

completed and test results were adaquate.

Detailed below are selected tests which were either reviewed or witnessed:

PROCEDURE EQUIPMENT / TEST

PT/2/A/4401/01B Component Cooling Train 2B Performance Test

PT/2/A/4401/05A Component Cooling Train 2A Heat Exchanger

Performance Test

PT/2/A/4401/05B Component Cooling Train 2B Heat Exchanger

Performance Test

PT/1/8/4350/23A Hydrogen Mitigation System Test

PT/2/A/4204/05 ND Valve Stroka Timing - Shutdown

PT/2/A/4206/02 NI Valve Stroke Timing - Quarterly

PT/2/A/4204/02 ND Valve Stroke Timing - Quarterly

PT/2/A/4209/02 NV Valve Stroke Timing - Quarterly >+

PT/2/A/4209/03 NV Valve Stroke Timing - Shutdown

On July 21, a Valve Stroke Timing (VST) test was conducted on Residual

Heat Removal (ND) Valve 2N058A, ND Heat Exchanger to Centrifugal Charging

Pumps 2A and 2B Block valve. This normally closed valve separates the ND

system from the suction piping of the Chemical and Volume Control (NV) and

Safety Injection (NI) systems, and is user. during the sump recirculation

phase of a Loss of Coolant Accident to provide NV and NI suction from ND.

At the time of the test Unit 2 was in Mode 5 with reactor coolant (NC)

system pressure at approximately 325 p31 9 ND train B was in operation in

the normal residual heat removal mode and, therefore, also at approxi-

mately 325 psig. ND train A was idle, but pressurized from train 8

through the ND suction cross connect. The portions of the NV and NI

systems downstream of 2ND58A have design pressures of 220 and 240 psig,

respectively. When 2N058A was opened, these portions of NV and NI wer s

overpressurized to NC s.vstem pressure via ND. As a result of the

overpressurization, a relief valve, 2NV229, set at 220 psig, lifted and a

leak developed at the body-to-bonnet joint of valve 2NV1025, Volume

Control Tank to Positive Displacement Pump Isolation. Subsequently, Duke

Design Engineering conducted an Operability Evaluation and Justification

for Continued Operation and found that the overpressurized systems were

not overstressed and were considered operable.

The VST test was being conducted in accordance with McGuire procedure

PT/2/A/4204/05, ND Valve Stroke Timing - Shutdown. This procedure did not

contain any limits or precautions preventing the test from being conducted

with pressure 'in excess of design pressure of the involved systems. The

procedure did separate the two ND trains on the discharge side of the ND

pumps, but left the ND pump suction side cross connect open, allowing full

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pressure to remain on the idle A train to which 2ND58A is connected. The

failure of the procedure to specify an upper pressure limit for conducting

the test constitutes a violation of Tech Specs 6.8.1 for an inacequate

procedure. (Violation 370/88-23-01)

The inspector reviewed other VST procedures for similar situations.

Procedure PT/2/A/4206/02, NI Valve Stroke Timing - Quarterly, contained a

deficiency in that the VST test of 2NI136B could overpressurize NI pump

suction piping if ND pressure exceeded 240 psig at the time of the test.

Similarly, no limits or precautions or prerequisite system conditions

existed in the procedure to prevent the occurrence.

Operations initiated Problem Investigation Report (PIR) 2-M88-0187

documenting the overpressurization shortly after the occurrence on July

21, 1988. Subsequently, Compliance contacted Design Engineering and

received a verbal operability determination on the same day, prior to the

unit entering Mode 4. Compliance assigned corrective action on the PIR to

Maintenance to repair the leak on NV1025, but did not require evaluation

by Performance, the group responsible for the test. As a result, Proposed

Resolution of Problem, as stated on the PIR, only involved repairing the

leak. No corrective action addressing the root cause of the problem, the

procedure inadequacy, was formally assigned. This situation became

evident when the inspector began investigating the problem on August 16.

Performance personnel stated that they recalled the overpressurization

event, but acknowledged that no corrective action had been taken or

investigation conducted because the PIR had not been received assigning

such. Upon questioning by the inspector, corrective action was undertaken

to address the root cause of the event. Compliance considers the

inadequacy of the PIR to assign corrective action only to Maintenance to

be an isolated occurrence. The NRC will further review the PIR process

for any programmatic deficiencies that may be involved. This is identi-

fied as an Unresolved Item. (URI 369,370/88-23-03)

5. Maintenance Observations (62703)

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.

No violations or deviations were identified.

6. Licensee Event Report (LER) Followup (90712,92700)

The following LERs were reviewed to determine whether reporting require-

ments have been met, the cause appears accurate, the corrective actions

appear appropriate, generic applicability has been considered, and whether

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the event is related to previous events. Selected LERs were chosen for

more detailed followup in verifying the nature, impact, and cause of the.

event as well as :.orrective actions taken.

The following LERs are considered closed:

7. Follow-up on Previous Inspection Findings (92702)

The following previously identified items were reviewed to ascertain that

the licensee's responses, where applicable, and licensee actions were

in compliance with regulatory requirements and corrective actions have

been completed. Selective verification included record review,

observations, and discussions with licensee personnel.

(C'esed) Violation 369/86-28-06, Inoperable Unit 1 Safety Valve.

Corrective actions have been taken and regional NRC inspectors have found

present test methods acceptable

(Closed) Violation 369, 370/87-04-01, Train B Containment Spray and

Train A SSPS Removed From Service Simultaneously. Corrective itctions have

been taken and a supplemental response was submitted due to a concern

raised in Inspection Report 369, 370/88-12.

(Closed) Violati n 370/86-35-03, Failure to Properly Implement Procedures

During A Startup Causing A Spill _. The licensee denied the violation as

written in that they did not agree that the cause of the spill was a

failure to follow procedure. The licensee believed the cause of the

problem was an inadequate procedure which has now been changed to more

clearly specify what actions are required. It is clear that the operator

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could have prevented the spill, however, the procedure was deficient.

A violation of NRC requirements did occur and corrective actions for

this specific instance have been taken.

(Closed) Unresolved Item 369/86-35-04, Resolve Adequacy of Temporary

Modification Safety Evaluation on KC Surge Tank Manway Covers.

A permanent modification has been implemented and this item is

considered closed.

(Closed) Viulation 369, 370/87-04-02, Failure To Control Removal and

Restoresiva of Containment Air Return Fan Curbing Sections. The procedure

has been revised to control removal and restoration of the curbing

sections.

8. Testing of the Turbine Ori'mn Auxiliary Feedwater Pump Turbine

After heat up following the Unit 2 rafueling outage the licensee

discovered that SA-48, one of the two ' team admission valves to the

turbine driven auxiliary feedwater (TOCA) pump, was leaking and the TOCA

pump was rotating at 400 rpm. The licensee cycled the valve in an attempt

to seat it but the valve would not seat properly. The licensee considered

the TOCA pump operable and intended to allow the pump to continue to

operate at 400 rpm until the p11nt returned to power operation and then

repair SA-48. The inspectors pointed out that IE information notice 86-14

documented a similar occurrence at Crystal River in which the same type of

TOCA pump tripped on overspeed when auto started from 160 rpm due to a

leaking valve. The licensee stated that their previous experience in this

area indicated that the TDCA pump would not trip on o <erspeed. In order

to prove operability the licensee committed to simulating an auto start

with the turbine initially rotating at 400 rpm. The TDCA pump was started

on July 27, 1988, in accordance with OP/2/A/6250/02, Auxiliary Feedwater

System, with the TDCA pump initially rotating at 400 rpm. Step 2.5 of the

procedure directed the operator to set the TOCA pump speed controller to

zero, start the pump, and raise the speed. After the operator set the

TOCA pump speed controller to zero the inspectors pointed out that this

start did not simulate an automatic start therefore the evolution would

not test the ability of the governor to prevent an overspeed trip when

starting from 400 rpm. The operator agreed, placed the speed control at

full speed, and ran the test with satisfactory results.

The procedure, however, was not changed as required by Station Directive

4.2. The operator, at the direction nf the Shif t Supervisor, noted on the

cover sheet of the procedure that the TDCA pump was started with the

controller at the max position but did not process the required change to

the procedure prior to or af ter perforeance of the OP. Station Directive

requires that a change of this type be processed as a major procedure

change iricluding extensive review and approval by two aualified reviewers

at least one of whom holds a Senior Reactor Operator license. Operations

Management Procedure (OMP) 1-2, Use of Procedures, paragraph 7.1.G

provides guidelines on what actions should be taken when a specific step

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in a procedure does not have to be performed. This OMP allows a step to

be marked "N/A" by a supervisor that holds an SR0 license, however, in the

case described above the step could not be marked "N/A" since the step

included startirg the TOCA pump. The OMP was not str ctly adhered to in

this instance and the licensee is conducting training on OMP 1-2, The

failure to make the procedure change in accordance with Station Directive

4.2 and meet the requirements of OMP 1-2 is identified as a second example

of a violation of TS 6.8.1. (370/88-23-01)

9. Feedwater Isolation Events

On July 24, 1988, at 5:40 p.m., a Unit 2 ESF actuation (feedwater

isolation) occurred when the low Tave setpoint was reached with the

reactor trip breakers open while in Mode 3. At the time, maintenance

personnel were preparing to apply leak sealant to stop a leak on a main

steam drain valve, 2SM-63. The valve had been tyenad to replace the air

supply solenoid with a straight line of tubing to maintain the valve shut

(air to shut / spring open) for the application of sealant. Once the air

line was disconnected and the valve was opened, the personnel left the

area for twenty to twenty five minutes to obtain additional ~ fittings that

were required. During this time the primary plant cooled down from 557

degree F to 553 degree F low Tave setpoint causing the feedwater

isolation.

The low Tave setpoint had recently been decreased to the low-low Tave

valve (553 degree F) through a Nuclear Station Modification (NSM). It

appears that operations personnel were not trained on the NSM so they were

unaware of the fact that a feedwater isolation would occur at 553 degree

F. This item is identified as an Unresolved Item (URI 370/88-23-02)

pending completion of the licensees investigation. The licensee stated

that an operations person will be assigned September 1,1988, to review

NSMs for operational considerations and training of operators prior to

implementation.

At 8:30 p.m. on July 24, 1988, another feedwater isolation occurred while

in Mode 3. IAE personnel were testing Channel 1 of the reactor protection

system when a signal comparator card on Channel III failed causing the

isolation. The card was subsequently replaced.

10. Diesel Generator Waiver of Compliance

In a telephone call on July 15, 1988, and letters dated July 15 and 19,

1988, Duke informed NRC staf f that it is not possible to comply with the

current McGuire Technical Specification (TS) 4.8.1.1.2.e.6)c). This

surveillance TS requires all but three automatic diesel generator (DG)

trips to be automatically bypassed during simulation of a loss-of-offsite

power in conjunction with an engineered safety features actuation test

signal. This TS can not be met as presently written because, in fact,

there are four DG trips not automatically bypassed in the design rather

than three. Similarly, there are two breaker trips not automatically l

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bypassed rather than the one presently recognized in the TS. Duke

requested that the TS be corrected on an emergency basis to avoid all

diesels being declared inoperable and the attendant requirement for

shutdown and extended refueling outage for McGuire Units 1 and 2

respectively.

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NRC staff reviewed Duke's evaluation and the justification provided in

+ heir letter regarding the DG operability.

. They agree that the time

overcurrent diesel generator protective trip and the generator diffaren-

t4al breaker trip should not be automatically bypassed when conducting the

above : cited surveillance test. NRC staff granted a temporary waiver of

compliance for the above TS. This waiver of compliance was in effect

through July 22, 1988, while the processing of the emergency TS change was

processed.

Licensee amendments 90 to NPF-9 and 71 to NPF-17 wer e issued on July 22,

1988 changing the TS requirements.

11. Exit Interview (30703)

The inspection findings identified below were summarized on August 19,

1988, with those persor.s indicated in paragraph 1 above. The following

items were discussed in detail:

(OPEN) Violation 370/83-23-01, Failure to Follow Procedures /

Inadequate Procedures (paragraphs 4 and 8).

(OPEN) Unresolved Item 370/88-23-02, Follow up on operators being

unaware of The Implementation of A Modification which led to an ESF

Actuation (paragraph 9).

(OPEN) Unresolved Item 369,370/88-23-03, Follow up on PIR Process to

ensure corrective actions identified (paragraph 4).

The licensee representatives present offered no dissenting comments, nor

did they identify as proprietcry any of the information reviewed by the

inspectors during the couree of their inspection.

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ML20154F991

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