ML20214W973

Insp Repts 50-369/87-14 & 50-370/87-14 on 870421-0522. Violations Noted:Failure to Document Operating Cycles & Maintain Tech Spec Action Item Logbook.Deviation Noted in Area of Fire Protection

ML20214W973
Person / Time
Site:	Mcguire, McGuire
Issue date:	06/01/1987
From:	Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20214W911	List: ML20214W908 ML20214W933 ML20214W957 ML20214W973
References
50-369-87-14, 50-370-87-14, IEB-86-003, IEB-86-3, IEIN-85-094, IEIN-85-94, NUDOCS 8706160277
Download: ML20214W973 (16)

See also: IR 05000369/1987014

Text

~~

T' * T

,

"

- km neig, " UNITE 3 STATES

- .s '

g 'o

NUCLEAR RE!ULATORY COMMISSION

[ _n REGION 11

,

g

• '

, j: 101 MARIETTA STREET,N.W.

4

s ATLANTA, GEORGI A 30323

\;....*/

'

Report Nos:.50-369/87-14.and 50-370/87-14

Licensee: Duke Pcwer Company

'422 South Church Street

Charlotte, NC 28242

Facility Name: McGuire Nuclear Station-1 and 2

Docket Nos: 50-369 and 50-370.

License Nos: NPF-9 and NPF-17

Inspection Conducted April 21, 19 7 - May 22, 1987

Inspectors: a b

ident Inspector

o7f/#2

Date' Signed

W.h/An Ordle'rs, Senp

S. Gue'nther, Resident nspe or

.

A sz We

"Date' Signed

Approved by: _ T. A. Pe'ebTes, S'ection Chief

4!///2 ~

D' ate Signed

Division of Reactor Projects

SUMMARY.

Scope: This routine unannounced inspection involved the areas' of operations

safety verification, surveillance testing, maintenance' activities,. follow-up of

~

previous enforcement actions, refueling activities, design change activities,

and independent inspection in the fire protection area. -

~

Results: Of the areas inspected, two , viol.ations were. . identified:

-

failure to document transient operating, cycles and'make Special_ Reports as

required by the Technical Specification,s; ,

- failure to maintain the Technical Specification Actio( Item Logbook as

required by plant procedures; and

.

One Deviation was also identified in the area of plant fire protection.

~

t

f

8706160277 870603

PDR ADOCK 05000369

<

G PDR

,

_.

.

.

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

• G. Gilbert, Operations Engineer

• J. Snyder, Performance Engineer

• D. Brandes, Design Engineering

• T. Lyerly, Instrumentation and Electrical

• W. Reeside, Operations Engineer

• E. Estep, Project Engineer

Other licensee employees contacted included construction craftsmen,

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

personnel.

• Attended exit interview

2. Exit Interview (30703)

The inspection scope and findings were summarized on May 22, 1987, with

those persons indicated in paragraph 1 above. Two violations concerning

multiple examples of failure to follow an Operations Management Procedure,

and failure to document and report transient operating cycles were

discussed. A' deviation from an NRC commitment regarding the plant's fire

protection equipment, unresolved items regarding auxiliary feedwater

system pressure switch ' testing, D/G operability, and post maintenance

valve testing were also 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 more information is

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

or deviation. Three new unresolved items were identified during this

report.

4. Plant Operation (71707)

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

.

.

2

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 in the main,

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 reporting period included, but were not

limited to, Unit 2 reactor building, 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.

a. Unit 1 Operations ,

Unit 1 operated at essentially full power for the entire reporting

period.

b. Unit 2 Operations

Unit 2 entered the reporting period at full power and maintained that

status until about mid-day on April 30, 1987. At 10:43 a.m. that

morning, channel "A" of the solid state protection system (SSPS) was

removed from service for periodic testing in accordance' with

PT/0/A/4601/08A. Action Statement No. 14 of Technical Specification (TS) 3.3.2 allows one channel of SSPS to be bypassed for up to two

hours for surveillance testing, provided the other channel is

, operable. Problems were encountered during the channel "A" testing

sequence and troubleshooting efforts were initiated. At 12:43 p.m.,

the allowable surveillance testing period expired and the shutdown

requirements of TS 3.3.2, Action Statement No. 14, were invoked. A

controlled shutdown was initiated, a notification of unusual event

(NOUE) was declared and the appropriate notifications were made. The

power reduction continued until approximately 3:00 p.m., when channel

"A" of SSPS was returned to an operable status. An output circuit

board, which was designed to produce a main generator trip in

response to a main turbine trip (but is not used in the McGuire

System) was found to have failed and was replaced. The entire SSPS

channel was successfully tested prior to making the operability

declaration, exiting the TS action statement and terminating the

NOVE.

Reactor power level was stabilized at about 45's following this

transient and was maintained at that approximate level until the

morning of May 1, when a scheduled refueling shutdown was initiated.

The unit was taken off line at 3:39 p.m. on May 1 and subsequently

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

~_ .#

_

i

!

-3.

.

entered Modes 2 - (startup) and 3' (hot standby) . at 3:56. p.m. and

e4:00.p.m., respectively. The' . reactor coolant- system cooldown

. continued without incident and Modes 4 (ho't shutdown) and.5'(cold

shutdown) were. achieved at 3:49 a.m. and 11:52 a.m., respectively, on

,

May 2. A problem regarding the documentation .of entry into. a TS-

_, - Limiting . Condition. for 0peration (LCO) action statement, as.. required

by Operations Management Procedure 2-5,; during the change in

operating modes, is discussed elsewhere'in this report.

On the-morning of May 3, the . unit was in Mode 5 with valve 2NC34, a

pressurizer power . operated relief valve (PORV), aligned, in1the low-

pressure mode when at 10:42 a.m. , the "B" reactor coolant (NC)- pump

was started in order to initiate a crud release and cleanup. The

resulting pressure transient caused 2NC34 to lift at about 368-psig.

and remain open for approximately three seconds prior._to reseating'at

about.300 psig NC pressure.

The incident detailed above prompted the~ inspector to investigate the

-documentation of this and previous plant transients. In the review-

it was determined that . Technical Specification 5.7.1. requires that.

specified components (e.g., reactor coolant system, reactor vessel)

be' maintained within the cyclic or transient limits of Table 5'7-1.

' Further, Technical Specification 6.10.2. requires that records of-

1 transient or operational cycles for those unit components identified

'in Table' 5.7-1 be retained for the duration of the unit Operating

License.

_

Station -Directive 3.1.23, " Documentation of Allowable Operating

' Transient Cycles", implements the program for documenting transients-

at the McGuire Nuclear Station as required by the TS. Included'among

the transient' cycles to be maintained and documented are NC System

heatups and cooldowns,- NC- System leak tests and normal pressurizer

PORV operation.

A cursory review of the plant's Masten Files on May 7 revealed the

absence of Transient Cycle Reports for the following transients:

.(1) Unit 1 Pressurizer PORV INC34 Operation on August 27, 1986.

(2) Unit 1 NC Heatup on September 5, 1986.

.(3) Unit 1 NC Side Leak Test on September 7, 1986.

(4) Unit 2 Pressurizer p0RV 2NC34 Operation on November 15, 1986.

(5) Unit 2 NC He'atup on November 16, 1986.

The matter was discussed with the Reactor Engineering group in an

effort to determine the status of the missing reports. In a

memorandum dated May 8, the Reactor Engineering group stated that

reports for transients 2,4 and 5, listed above, had been located on

one of the desks in their office area, but that they had not been

approved or filed. Transient 3 had been identified at the time of

the occurrence, but the report had not been completed, and

_ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _

.

.

4 ~

. 4

transient I had not been identified and had apparently been

overlooked in their review of the reactor operators' log books.

As discussed in.Section 5.2.1.5 of the McGuire Final Safety Analysis

-

Report, five ASME (American Society of Mechanical Engineers)

. operating conditions were considered in the design of the NC System:

normal, upset, emergency, faulted, and testing. The design

transients selected for monitoring are representative of operating

conditions which could be of possible significance in component

cyclic behavior and equipment fatigue evaluation. The fact that the

Unit 1 operating transient of August 27, 1986, was overlooked is

exacerbated by the apparent lack of discipline evident in the

completion of several other operating transients on both units and is

i

an apparent violation of the plants' procedures and the Technical

Specifications.

In a related effort, _the inspector requested the Licensing and

Compliance group at the plant to confirm that the Special Reports

required by TS 3.4.9.3 had been submitted. Action Statement (c) of

that Specification directs that a Special Report be prepared and

submitted to the Commission pursuant to Specification 6.9.2 within 30

days in the event the PORVs are used to mitigate a RCS pressure

transient. On May 19, the inspector was informed that the required

Special Reports had not been prepared for transients 1 and 4 listed

above. These failures to comply with the requirements of TS 3.4.9.3,

together with the related non-compliance discussed in the previous

paragraph, collectively constitute Violation (50-369,370/87-14-01).

Unit 2 remained in Mode 5 until 11:20 p.m. on May 9, when the first

reactor pressure vessel (RPV) head closure stud was detensioned and

Mode 6 (refueling) operation commenced. The RPV head was removed on

May 17, and core alterations were begun on May 18. At the close of

the report period core off load continued.

5. Technical Specification Action Item Logbook (TSAIL) (71707)

Operations Management Procedure (OMP) provides instructions for

documenting operations in a degraded condition as permitted by a Technical

Specification (1S) action statement for the existing mode. The following

deficiencies in maintaining the Unit I and 2 TSAILs were detected by the

inspectors while performing routine log review during the inspection

period,

a. As permitted by TS 3.4.4. , Unit 2 had operated from November 17,

1986, until the unit was shut down for the outage with one

pressurizer power operated relief (PORV) block valve isolated and

deenergized. This action was documented in the Unit 2 TSAIL (entry

1. 12279) as required by OMP 2-5. The isolated PORV (2 NC 32) is one

of two valves required to be operable for overpressure protection,

per TS 3.4.9.3. , when any reactor coolant system (RCS) cold leg

- . .

__ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

!

"

l: .

i 5

,

'

temperature is less than, or equal to, 300 degrees Fahrenheit in -

Mode 4, and during Mode 5 and 6 operations (with the vessel head on).

Action Statement (a) of TS 3.4.9.3 requires that, with one PORV

. inoperable, it must be restored to 'an operable status within seven

days, or the RCS must be depressurized and vented through a vent of

at least 4.5 square inches within the next eight hours. This action

statement was entered sometime prior to 11:52 a.m. , on May 2,- 1987,

the time when Mode 5 (average RCS temperature at or below 200

degrees F) operation was commenced. However, the TSAIL entry made to

document the degraded condition indicated the start time for the

seven-day clock as 20:40 on May 2. This erroneous entry was brought

to the attention of the Unit Coordinator, who later resolved the

discrepancy with the Shift Supervisor on duty at the time and

corrected the problem. The actual time was 10:40 a.m., May 2.

b. Technical Specification 3.7.6 requires that two independent control

area ventilation systems (VC/YC) be operable in all operating Modes.

Train "A" of VC/YC is normally powered from Unit 1 and train."B" from '

Unit 2, however, both trains are capable of being powered from the

same unit. The power supply transfer requires that both sources of

power to the train being swapped be deenergized and danger tagged,

thereby making the train inoperable and requiring a TSAIL entry per

OMP 2-5. On May 4,1987, train "A" was transferred from Unit 1 to

Unit 2 to support engineered safety features testing requirements;

,

TSAIL entry Nos. 12898/13146 apply. While reviewing the shift

i

'

turnover documentation on May 6, the inspector noted that train "A"

had been transferred back to its normal Unit 1 supply, but that no

TSAIL entry had been made to document the degraded condition. This

was brought to the attention of the Unit Coordinator and late entries

(Nos. 12912/13180) were made to cover the event.

!

! c. A review of Shift turnover documentation on May 7,1987, revealed

that train "B" of VC/YC had been transferred to Unit 1 during the

l night, but, once again, the degraded condition was not logged in

either Unit's TSAIL as required by OMP 2-5.

'

'

d. On March 30, 1987, at 11:29 a.m., while Operations (OPS) personnel

were attempting to perform a routine diesel generator operability

l test, Diesel Generator 2B (D/G 28) experienced a trip following a

normal start. It was determined that periodic maintenance (PM) was

being performed by Instrumentation and Electrical (IAE) personnel on

a pressure switch which trips the diesel when in the manual start /run

l-

mode if the cooling water pressure is below the setpoint. Due to a

i breakdown in communications, the operators were unaware that the

pressure switch was isolated and removed when they started D/G 28.

The pressure switch was replaced and a successful diesel generator

operability test was performed.

Unit 2 was in Mode 1, power Operation, at 100% power, at the time of

this incident.

L____..______

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

.

,

.

6

Analysis of the circumstances surrounding this event indicate IAE

personnel began a series of PMs on D/G 2B'on March 30, 1987, at

approximately 0830 a.m. By approximately 0900 a.m., they were

preparing to calibrate . diesel cooling water pressure switch . KDPS

5051, and contacted the Shif t Supervisor to advise him that the

manual start circuits for the diesel would be inoperable for

approximately one hour. The IAE personnel, were cleared to begin

work by the Shift Supervisor.

Work on the Voltage Regulator was also in progress by a different IAE

crew. This PM disabled the D/G 2B emergency start /run circuit. Log

entries had been made by OPS personnel to document this and declare

D/G 2B inoperable in preparation for the PM work. The work on the

Voltage Regulator was finished by approximately 10:30 a.m. and IAE

contacted the Control Room to arrange for the post maintenance diesel

test.

Control Room personnel contacted the Operations Periodic Test Group,

to have the operability test run. Two operators responded: one to

the Control Room and one to the D/G Room. The two operators were

unaware of either maintenance activity. At about this same time the

IAE crew working on the pressure switch discovered a frayed wire,

isolated the instrument line, removed the' component and took it to

the IAE shop for further evaluation. They were not in the D/G room

when the operator arrived to conduct the test.

At 11:29 a.m. the D/G was manually started. 20 seconds later it

tripped on a low cooling water pressure signal. The cause was, at

that time, recognized by the Shift Supervisor and was confirmed by

the operator in the D/G Room. The IAE crew working on the pressure

switch was contacted and then reinstalled the pressure switch. At

approximately 12:02 p.m., D/G 2B was again started and the

operability test was successfully completed.

Operations Management Procedure 2-5, Technical Specifications Action

Items Logbook, Section 7.0 (P) requires that any system or component

which is made inoperable by taking one of its support systems

(instrumentation, controls, electrical power, cooling or seal water,

lubrication or other required auxiliary equipment) out of service

shall be logged.

Furthermore, the definition of operability as specified in McGuire

Technical Specification 1.18 states that a system, subsystem, train,

component or device is OPERABLE when it is capable of performing its

specified function (s), and when all necessary attendant

instrumentation, controls, electrical power, cooling or seal water,

lubrication or other auxiliary equipment that are required for the

system, subsystem, train, component, or device to perform its

function (s) are also capable of performing their related support

function (s).

.. .

.

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

. . . . ..

.

.

7

The specified functions of the. emergency diesel generators include.

manual operation from the control room (Reference The Emergency

Diesel Generator and Related Systems, MCSD-0120-00.01 Rev.3, 7/16/85

and applicable Emergency Procedures).

A controversy exists over whether or not the D/G was inoperable with

the manual start /run feature inoperable and whether logging the

pressure switch would have made any difference in the outcome of this

event. In that vien, this specific event will be carried as on

Unresolved Item (50-370/87-14-02).

The whole point of this scenario being the inadequate implementation

of an administrative vehicle designed to aid the operating staff in

maintaining cognizance of plant status.

Although all four events are valid examples of deficient

implementation of OMP-2-5, items two and three collectively are being

identified as an apparent violation of TS 6.8.1 (50-369,

370/87-14-03).

6. 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.

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/0/A/4600/140 -

Nuclear Instrumentation System Power Range N-41

Analog Channel Operational Test

PT/2/A/4150/14 -

PORV Channel Functional Test

IP/0/A/3010/06 -

Reactor Protection System Response Time Test

PT/0/A/4601/008A -

Solid State Protection System (SSPS) Train "A"

Periodic Test Above NC System Pressure of 1955

PSI

PT/2/A/4200/09A -

Engineered Safety Features (ESF) Actuation

Periodic Test

PT/1/A/4252/07 -

Auxiliary Feedwater System Performance Test

,. -

.. -_ _.

.

8

Identified below is an opporant surveillance testing inadequacy with

auxiliary feedwater suction valves. f

7. -Auxiliary Feedwater Pressure Switch Calibration (62703)

Each McGuire unit is equipped with three auxiliary feedwater (CA) pumps,

two motor and one turbine-driven, to provide makeup to ~ the steam

generators for decay heat removal capability when the main-feedwater pumps

are unavailable. The normal, preferred source of suction to the CA pumps

comes from either the upper surge tank, the CA condensate storage tank or

the condenser hotwell. The assured source of water, while not preferred

because of low purity, comes from the nuclear service water (RN) system.

The RN supply to each CA pump is normally isolated by two valves in

series, one in the CA system and a second in the RN system. Each of these

valves is designed to open automatically upon receipt of a low pressure

signal from single pressure switches, which sense the suction pressure for

their associated CA pump, s

On May 9, 1987, Instrumentation and Electrical (IAE) personnel determined

that the pressure switch (ICAPS 5002) which controls the automatic

repositioning of valve ICA15 to supply RN to the,1A motor-driven CA pump

was miscalibrated. They found that the pressure switch had been

previou;1y calibrated without taking into account the static leg of r

approximately 11 feet of water always present in the instrument line. The'

1A CA_ pump was declared inoperable until the pressure switch was correctly

calibrated. The calibration records for the other CA pump suction

pressure switches were checked to verify proper ~ calibration; no other

problems were detected.

The inspectors requested the licensee to make a determination whether the

1A CA pump suction would ever have transferred to the RN system as

designed and to research the equipment history for ICAPS 5002 to find out

how long it had been out of calibration. In a preliminary evaluation of

the incident, the licensee has concluded that, since the pressure exerted

by the instrument's reference leg exceeded the switch's setpoint, the

switch would never have actuated. They consider that the incident is

reportable under 10 CFR 50.73 and that CA train 1A was inoperable prior to

recalibration of the pressure switch on May 9.

Preliminary indications are that ICAPS 5002 had been out of calibratien'in

excess of one year; a more precise determination will be made during the

Incident / Problem Investigation (PIR No. 1-M87-0083).

Technical Specification 3.7.1.2 requires at least three independent steam

generator CA pumps and associated flow paths to be operable in Modes 1,2

and 3. Surveillance requirement 4.7.1.2.b.3 verifies that the valve in

the suction line of each CA pump from the RN system automatically actuates ,~

to its full open position within less than, or equal to,13 seconds on a

low suction pressure test signal. This surveillance requirement,

implemented by PT/1/A/4252/07, was last successfully performed on

1

!

.

.

9

March 20, 1986, but it does not challenge the system with an actual low

pressure condition in the pump's suction:line.

Pending the completion of the licensee's PIR and further review of the

surveillance testing pursuant to TS 4.7.1.2.b.3, this issue will remain

unresolved (50-369/87-14-04).

8. ESF Actuation Testing (61726)

During the report period the inspectors witnessed Unit 2 ESF Actuation

'

testing. The test is run on both trains, one train at a time and is

designed to:

-

To demonstrate the diesel generator's ability to restart and load in

response to a manually initiated safety injection, Phase A Isolation,

Phase B Isolation and Blackout after having been run or 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and

shutdown.

-

To demonstrate that when the D/G paralleled with offsite power, a

safety injection returns the D/G to standby status and the emergency

loads are sequenced onto the offsite power supply.

-

To demonstrate D/G starting load shedding and emergency load

sequencing in response to a blackout.

.

To document the correct movement of valves in response to a safety

injection, Phase A Isolation, and Phase B Isolation which are

operated pursurant to above.

The D/G is operated at 110% rated load for two hours, followed by at

least 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> at 100% rated load and then shutdown. Within five

minutes a SI, Phase A and Phase B Isolation and blackout are manually

initiated with the D/G subsequently starting, accepting and operating

the emergency laod for at least five minutes. Power is restored to

the 4Kv transformer, the D/G synchronized, and the load transferred,

with the D/G being returned to standby status. The D/G is paralled

with offsite power and a SI manually initiated. The D/G nreaker is

auto tripped with the D/G returning to standby status as the

sequencing of loads onto offsite power progresses. D/G parameters,

system response times, and correct valve movement are recorded.

To test ESF response to a train blackout the 7KV feeder to 7/4KV

transformer is tripped initiating a B/0. The D/G auto starts, load

shed occurs, sequencing for B/0 progresses and the D/G carries the

B/0 loads for at least five minutes. The sequencer is reset and the

D/G us manually tripped with load shedding, D/G restarting and load

sequencing reinitiated. D/G paragmeters, corrrect valve movements,

response times, and system responses are recorded.

i

'<j

f

.

.

10

- At the - end of the report period, the inspectors review of the ESF

tests was not complete. -This item will be carried as an Inspector

Followup Item. (50-370/87-14-05)

9. 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.

An Unresolved Item (50-369,370/87-08-02), regarding the maintenance and

testing of ' valve INM-26 as documented in a previous Inspection Report, has

been resolved as a Licensee' Identified Violation. This issue is discussed.

in detail later in this report.

10. Unit 2 Refueling (60705, 60710)

As discussed earlier in this . report, Unit 2 commenced a refueling outage

on May 1, 1987. In preparation for refueling, the inspector reviewed a

number of licensee procedures for the -conduct of refueling operations to

ascertain their adequacy. The following procedures were reviewed:

OP/2/A/6100/02 - Controlling Procedure for Unit Shutdown

OP/2/A/6150/06 - Draining the RCS

OP/0/A/6550/04 - Fuel and Component Handling

MP/2/A/7150/057 - Reactor Head Removal and Replacement

PT/2/A/4550/022 - Total Core Unloading

PT/0/A/4550/024 - Fuel Assembly Examination

OP/0/A/6550/01 - Receipt, Inspection and Storage of New Fuel

PT/2/A/4550/21 - Inspection and Storage of New Fuel

0P/0/A/6550/11 - Internal Trsosfer of Fuel Assemblies / Inserts

Enclosure 4.6, "NC Level InctOamer ation Overlap", was noted to be missing

from.the Master File cop' t ~ 0F 'A/6150/06. The Operations Procedure

Group was informed of the . l se ,ncy and verified that the Control Copy

of the OP maintained in the Control Room did have the necessary enclosure.

The licensee, took prompt action to correct the deficient Master File

procedure.

PT/2/A/4550/01 was noted to have been recently revised to incorporate

documentation for the removal of the curbs which protect the containment

air return (VX) fans from the in' flux of excessive amounts of water during

containment spray system operation. The failure to control the removal

and reinstallation of the VX curbing was the subject of recent enforcement

action against Duke Power.

\

m

-

te

. .:

.

11

. Pre-refueling and refueling activities were observed and monitored to.

ascertain whether Technical Specification requirements were satisfied and

'

. activities _were conducted in accordance with approved procedures.

-

On:May 5,.1987, while the reactor ~ coolant (NC) System was being drained,

in accordance with OP/2/A/6150/06, inconsistencies were. noted between the

various RPV level instruments (i.e., installed -wide and narrow range

meters, sight glass and tygon tube). In light- of recent incidents' at

other'similar facilities during mid-loop operations, and as required by.

their procedures, the licensee proceeded very cautiously to ensure that

adequate residual : heat- removal ~ system suction was maintained. .The

e licensee is taking a pro-active approach to the_ issue and has-initiated an

. Incident' Investigation (Report No. M87-031-2) to determine the cause ' of

the instrument inaccuracies and to propose corrective actions to preclude -

recurrence. This . investigation will be reviewed by. the inspectors when

complete.

No violations or deviations were identified.

Ell. Auxiliary. Feedwater Pump Halon Fire. Suppression System

The- Unit 1 and 2 auxiliary feedwater (CA) systems at McGuire consist of

two motor-driven pumps and one ' turbine-driven pump. The turbine-driven

- pump rooms are' protected from fire by. halon 1301 fire extinguishing

systems consisting of two halon cylinders each (one main and one reserve),

located in'the basements of the unit turbine buildings.

Subsequent to ' the maintenance problems _ encountered -.with the diesel:

generator halon fire suppression' systems, as documented in NRC Inspection

Report Nos. 50-369,370/87-12, the inspector examined the CA halon systems

to determine- whether they were susceptible toi similar' problems. During

the inspection, it was noted that the Unit 2 halon cylinders were mounted

to the turbine building wall in a manner which would prevent their

becoming a missile hazard. In comparing the Unit 1 cylinder support with

that.on Unit 2, it was noted that the only support afforded to the Unit 1

CA halon cylinders wa's that provided by the discharge pipe. The inspector

informed the Unit Coordinator of the apparent deficiency and later

verified that the cylinders had been temporarily restrained with a chain.

Further research and discussions with licensee personnel revealed the

following:

,

-

_The McGuire Nuclear Station Final Safety Analysis Report (FSAR), i

Section 9.5.1.2.1, states that the Fire Protection System is designed

to meet the standards developed by the National Fire Protection

Association (NFPA) where practicable. It further states that halon

1301 fire protection systems are provided for the turbine-driven CA

pump oil hazards _in the auxiliary building.

-r

.

.

12

-

NFPA Standard 12A, "Halon 1301 Fire Extinguishing Systems", Section

1-9.4.6, states that, when manifolded, containers shall be adequately

mounted and suitably supported in a rack...".

-

The ' Duke Power Company Administrative Policy Manual for Nuclear

= Stations, Section 3.11.3.4, states that the halon 1301 systems shall

be tested, maintained, and inspected in accordance with NFPA Standard

12A.

-

The McGuire Nuclear Station Fire Protection . Review Manual responded

to positions presented in Appendix A to Branch Technical Position

APCSB 9.5-1. Position E.4, "Halon-Suppression Systems," states that

the use of halon fire extinguishing agents should, as a minimum,

comply with the requirements of NFPA 12A. The licensee's response to

Position E.4 stated that approved halon 1301 systems were available

for the CA steam-driven pumps and did not take exception to the

Branch Technical Position.

-

Drawing MCM 1206.07-30, Sheet 3 illustrates the Unit 1 CA halon 1301

system as being rack mounted to provide suitable support.

The licensee's design engineering staff has acknowledged that the as

built Unit 1 CA halon 1301 system does not conform with the

applicable standards and has informed the inspector that action has

been initiated to correct the deficiency. This design deficiency is

classified as an apparent deviation from commitments made to the NRC

-(50-369/87-14-06).

12. I.E. Bulletin Closeout

(Closed) 369,370/86-BU-03, Potential Failure of multiple ECCS pumps due to

single failure of air operated valve in minimum flow recirculation line.

The licensee responded to IEB 86-03 in a letter dated November 10, 1986.

In their response the licensee stated the concern was previously

investigated as a followup to IEN 85-94. From this review, the licensee

determined that the ECCS minimum flow lines were adequately designed to

protect the pumps. In addition, the licensee stated the issue of single

failures and deadheading ECCS pumps was discussed extensively with the

NRC staff during the license review for Catawba, whose design is

essentially the same as McGuire. As a result of the reviews, the licensee

has concluded that McGuire does not have the potential for a single

failure causing the failure of more than one ECCS train. This item is

closed.

13. Inadequate Post Maintenance Procedure

As was previously reported (369/87-08), on February 24, 1987, valve

INM-26B, Reactor Coolant (NC) Hot leg Sample Header Outside Containment

Isolation, failed to operate correctly during a slave relay test.

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

'

,

V c >

. ,

- ,

. ' 13 '

A more: detailed review of the circumstances surrounding the event revealed

~

that Eon JJanuary -15, 1987, - valve : 1NM-268 : failed a - r'outine valve 1 stroke

timing' test. iThe 'cause of. the problem was determined to be an inoperable.

=

actuator motor- on :the valve. -The ' actuator was replaced on .Febr~uary. 9,

.1987. The valve owith the new ' actuator passed functional : testing and

operatedDsatisfactorily. until February 24, 1987.

On1this date,? performance (PRF) personnel performed a routine test of.the

SSPS slave relays. During_a portion.of the test valve.1NM-268 should have

closed and remained closed. ' Instead, the valve ' cycled continuously, as

along as the output relay was energized from the slave relay test -device.

With the output relay deenergized ~(normal), valve 1NM-268 - operated -

correctly with the control. board switch._ In other words, the valve would

not-have' isolated on an automatic ESF. signal.

-

IAE personnel investigated the problem with valve INM-268 on February 25,

~

1987. When the IAE technician removed the cover from the terminal block,

he detected what' appeared to be a metal to metal contact between

= termination ~ point'24 and. termination point 15. He bent the neckoof the

. ring' terminal on point 24 so that contact.was no longer made,

PRF personnel retested valve INM-26B which closed and remained closedJas

required.and operated satisfactorily with the control board switch.

Examination revealed a nick in the insulation. covering the metal sleeve of.

ring ~ terminal 24 which allowed the - metal to directly contact the barrel

nut below it.

The~ normal orientation when installing a single ring terminal is to

position -the metal sleeve facing away' from the terminal block. When the

= actuator for-valve INM-268 was replaced in February 1987, ring terminal 24

was installed with the metal sleeve facing 'the terminal. block. Upside-

down -if you will, increasing the possibility of creating a short circuit.

The short circuit. was most likely caused by the positioning of ring

-terminal 24 by the IAE technician during the most recent installation. A

review of applicable procedures revealed that this 'did not address- the

' positioning of ring terminals, nor precautions to take to avoid shor+.

circuits.

Discussions with licensee and a review of McGuire Incident Investigation

Reports did not reveal any valve malfunctions due to similar problems.

In report 369/87-08, the subject of post maintenance testing was opened as

an Unresolved Item. In as much as the licensee has determined that normal-

functional testing after valve repairs will still not include a test of

function when as SSPS signal is applied, the issue Item will remain

' unresolved, pending further review. (50-369,370/87-14-08)

I It appears that the root cause of this event was the inadequacy of the

applicable procedures. More specifically, Procedure IP/0/A/3066/02A,

I.

I

l

q.

~

-

'

,

"

w . [

-14' i

-

Installation, Removal ~, and Set-up of Rotork Actuators,_the procedure.which

delineates = thef directions for: rewiring -Rotork : actuators, contained .no

instructions for positioning'of ring terminals nor= precautions to take to

avoid short circuits. However, 'in' as much as' the problem was identified,

and corrected by the licensee, the event-contributes a Licensee Identified

- Violation. l(50-369/87-14-07)

-14. ._ Design,'De' sign Changes, and Modifications (37700)

_ Selected _ design ' changes and modifications that were d'etermined 'by the

licensee to :not-- require'. approval by the NRC were reviewed to ascertain

conformance with the requirements oflthe plant's Technical Specifications

and 10 CFR4 50.59.

Specifically, ' the following Nuclear Station Modifications (NSMs) and

associated work requests (WRs) were~ evaluated:

~

-

NSM MG-1-1930/MG-2-0700 - Move selected safety, injection,

WRs 94621, 94623' chemical volume and control, and: CA

System valve actuator - torque bypass

switches to' the actuator add-on. pack.

Reset torque bypass switches to 50*.' and

replace all jumpers' with qualified

wire.

-

NSM MG-2-0089,IRev. 1 -

Modify the-control rod gripper

WR 92717 on the reactor building rod control

cluster change fixture.

No violations or deviations were identiified.

15. LER Followup-

The Licensee Event Reports detailed below were reviewed in order to ~

determine if the licensee's review, corrective action and report of the

identified event and associated conditions are adequate and in conformance

with regulatory requirements, ' Technical Specifications, licensee-

conditions and licensee procedures and controls.

-The review, consisting of record review, direct observation or discussion

with licensee personnel was directed primarily at verifying that:

-

corrective action is appropriate to correct the cause of the event.  ;

-

corrective action has been or is being caken.

,

L ,

-

for corrective action not yet complete, that responsibility has been

assigned for' assuring completion thereof.

-

generic implications i f identified were incorporated in corrective

L action.

.

,- p4., -- -c,e, , w a--m es, e ,,y,w. um., +---.w. w-~-t-~t-r., .w mwy* y,.p w v v-y -ww,..e 9 f T 'r' , y- r y- e v, e-wn 't-* * w w e- w w - ar -- - --

m

.

15

'

Unit 1 Unit 2

-LER 86-04 LER 86-04

LER 86-06 LER 86-05

LER 86-07 LER 86-07

LER 86-08 LER 86-11

LER 86-09 LER 86-12

LER 86-13 LER 86-15

LER 86-18 LER 86-17

LER 86-02 LER 86-21

LER 87-01 LER 87-03'

LER 87-06 LER 87-05

No Violations or Deviations were identified.