Text

Insp Repts 50-269/91-03,50-270/91-03 & 50-287/91-03 on 910127-0223.Violations Noted.Major Area Inspected: Operations,Surveillance Testing,Maintenance Activities & Insp of Open Items
	ML15224A764
Person / Time
Site:	Oconee
Issue date:	03/08/1991
From:	Belisle G, Binoy Desai, Poertner W, Skinner P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML15224A762	List: ML15224A760; ML15224A763; ML15224A764;
References
	50-269-91-03, 50-269-91-3, 50-270-91-03, 50-270-91-3, 50-287-91-03, 50-287-91-3, NUDOCS 9103250098
	Download: ML15224A764 (13)
	v • d • e

644 REG4

UNITED STATES

o

NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTA STREET, N.W.

z

ATLANTA, GEORGIA 30323

Report Nos.: 50-269/91-03, 50-270/91-03,

50-287/91-03 and 72-4/91-03

Licensee: Duke Power Company

P. 0. Box 1007

Charlotte, NC 28201-1007

Docket Nos.: 50-269, 50-270, 50-287 and 72-4

License Nos.: DPR-38, DPR-47, DPR-55 and SNM 2503

Facility Name: Oconee Nuclear Station

Inspection Conducted: January 27 - February 23, 1991

Inspectors:_______

P. H. Skinner, Senior Resd nt

ector

Date Signed

B. B. Desai, Reside

Ins

t r

Date Signed

-3- 2-i>F

W. K.

rtner, Re

eqt Ispe

Date Signed

Approved by-

£o'e

J-7-q

. Bel ie,

Section Chief

Date Signed

Division of Reactor Project

SUMMARY

Scope:

This routine, announced inspection involved inspection on-site in

the areas of operations, surveillance testing, maintenance

activities and inspection of open items.

Results:

One violation was identified concerning a failure to follow

procedures associated with independent verification. Two unresolved

issues were identified concerning High Pressure Injection system

instrumentation and control of activities associated with various

component circuit breakers. Controls exhibited during mid-loop

operations have improved since the previous refueling outage. One

non-cited violation concerning missed surveillance was identified.

91O3250098 910308

PDR

ADOCK 05000269

C!

PDR

REPORT DETAILS

1. Persons Contacted

Licensee Employees

H. Barron, Station Manager

D. Couch, Keowee Hydrostation Manager

T. Curtis, Compliance Manager

J. Davis, Technical Services Superintendent

D. Deatherage, Operations Support Manager

B. Dolan, Design Engineering Manager, Oconee Site Office

W. Foster, Maintenance Superintendent

W. Gibson, Quality Assurance

T. Glenn, Engineering Supervisor

0. Kohler, Compliance Engineer

C. Little, Instrument and Electrical Manager

H. Lowery, Chairman, Oconee Safety Review Group

B. Millsap, Maintenance Engineer

M. Patrick, Performance Engineer

D. Powell, Station Services Superintendent

G. Rothenberger, Integrated Scheduling Superintendent

R. Sweigart, Operations Superintendent

Other licensee employees contacted included technicians, operators,

mechanics, security force members, and staff engineers.

NRC Resident Inspectors:

P. Skinner

W. Poertner

B. Desai

Attended exit interview.

2. Plant Operations (71707)

a. General

The inspectors reviewed plant operations throughout the reporting

period to verify conformance with regulatory requirements, Technical

Specifications (TS), and administrative controls. Control room

logs, shift turnover records, temporary modification log and

equipment removal and restoration records were reviewed routinely.

Discussions were conducted with plant operations, maintenance,

chemistry, health physics, instrument & electrical (I&E), and

performance personnel.

Activities within the control rooms were monitored on an almost

daily basis.

Inspections were conducted on day and on night shifts,

during weekdays and on weekends. Some inspections were made during

shift change in order to evaluate shift turnover performance.

2

Actions observed were conducted as required by the licensee's

Administrative Procedures. The complement of licensed personnel on

each shift inspected met or exceeded the requirements of TS.

Operators were responsive to plant annunciator alarms and were

cognizant of plant conditions.

Plant tours were taken throughout the reporting period on a routine

basis. The areas toured included the following:

Turbine Building

Auxiliary Building

CCW Intake Structure

Independent Spent Fuel Storage Facility

Units 1, 2 and 3 Electrical Equipment Rooms

Units 1, 2 and 3 Cable Spreading Rooms

Units 1, 2 and 3 Penetration Rooms

Units 1, 2 and 3 Spent Fuel Pool Rooms

Unit 3 Containment

Station Yard Zone within the Protected Area

Standby Shutdown Facility

Keowee Hydro Station

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

equipment status, and radiation control practices were observed.

b. Plant Status

Unit 1 operated at power for the entire reporting period. On

February 2, 1991, Reactor Coolant Pump 1A1 motor experienced a low

oil pot level.

This resulted in the pump being secured and a power

reduction to 40 percent. No obvious oil leak was identified.

Several gallons of oil were added to the motor, the pump was

restarted and the unit returned to 100 percent power on February 3,

1991.

Unit 2 operated at power for the entire reporting period.

Unit 3 operated at power until the generator was taken off line for

a scheduled End of Cycle (EOC) 12 refueling outage on February 13,

1991, at 3:00 p.m. While cooling down and depressurizing the

Reactor Coolant System (RCS) from hot shutdown, Reactor Protection

System (RPS) channels C and D actuated on low RCS pressure and

resulted in insertion of group 1 control rods. The reactor was

already subcritical and group 2 through 7 control rods had been

previously inserted at the time of the RPS actuation. The reactor

operator was monitoring the wide range RCS pressure meters which

were reading 30 psig higher than the narrow range (NR) RPS pressure

meters while reducing temperature and inserting group 1 rods.

During the rod insertion the RPS setpoint was reached and resulted

in the RPS actuation. A contributing factor to this unplanned RPS

actuation was that the shutdown procedure requires group 1 rods to

be inserted at 1850 - 1820 psig (RPS trip setpoint is 1800 psig),

but does not direct the operator to monitor the NR RPS pressure

3

instruments. A procedure change was submitted to change the

pressure at which group 1 rods are required to be inserted to allow

more time for rod insertion prior to reaching RPS trip setpoints. A

four hour NRC notification was made pursuant to the requirements of

10 CFR 50.72 b.2.ii.

At the end of the reporting period defueling

activities had commenced.

c. HPI Piggyback Problems

As a result of a followup item from a Self Initiated Technical

Audit, the licensee identified five potential problems that could

affect the High Pressure Iqjection (HPI) and Low Pressure Injection

(LPI) systems when in the piggyback mode of operation. These

potential problems included:

(1) potential insufficient HPI pump NPSH

(2) potential overflow/overpressurization of the Letdown

Storage Tank (LDST)

.

(3) potential inadequate Emergency Core Cooling System

(ECCS) flow

(4) inability to provide LPI pump minimum flow

(5) potential HPI pump runout.

These items are identified and addressed in a Special Report to the

NRC dated February 6, 1991.

The potential HPI pump NPSH problem during piggyback mode of

operation was resolved by removing procedural instructions which

could have allowed aligning the LPI discharge to both HPI and

Reactor Building Spray while in the piggyback mode of operation.

The potential overflow/overpressurization of the LDST during

piggyback mode of operation results from the suction pressure at the

HPI pumps due to the discharge pressure of the LPI pump potentially

being greater than the LDST relief valve set pressure of 106 psig.

This could result in the HPI pump minimum flow recirculation

returning to the LDST and eventually overfilling/overpressurizing

the tank. This could result in containment sump inventory being

lost out the relief valve to the bleed holdup tank. The piping

downstream of the relief valve and the bleed holdup tank are not

seismically qualified and are not safety related. To prevent the

LOST from overflowing/overpressurizing the licensee revised the

Emergency Operating Procedure (EOP) to open HP-363, the letdown line

to LPI pump suction isolation valve, upon entering the piggyback

mode of operation. This would divert the HPI mini-flow from the

LDST to the suction of the LPI pumps. The licensee also had the

option of shutting the HPI mini-flow recirculation isolation valves

to prevent recirculation flow back to the LDST but decided to open

HP-363 to provide mini-flow protection for the HPI pumps. The

piping downstream of the HPI mini-flow recirculation isolation

valves up to HP-363 is class "C" pipe. The inspectors questioned

whether class "C" pipe was acceptable since RCS containment sump

water would be flowing through the pipe during the piggyback mode of

II

4

operation. Review of the HPI design basis document determined that

the design basis for the HPI system states that piping that could

transport containment sump water is required to be class "B" pipe.

The licensee stated that the design basis document was incorrect and

that class "C" piping was acceptable per the original Oconee Design

Basis and that the HPI system design basis document would be

revised. The inspector is continuing the review of the

acceptability of this design evaluation. In addition, the inspector

also is reviewing the adequacy of the licensee's EOP procedure

revision in that the new procedure does not address shutting the HPI

mini-flow recirculation isolation valves if HP-363 can not be

opened, or if other single failures that could affect the mini-flow

flowpath occur. Included in this review is the appropriateness of

allowing containment sump water to be transported throughout the

non-safety portion of the HPI system with respect to radiation

levels in the Auxiliary Building. The licensee stated that a design

study would be performed to address any accessibility concerns;

however, this study was not completed prior to revising the EOP to

open HP-363. Discussions with the licensee determined that a

preliminary design study report is scheduled to be issued in mid

March. The licensee also identified that the LDST inlet and outlet

check valves were not tested in the closed direction in the

Inservice Testing Program. This item is identified as Unresolved

Item 50-269,270,287/91-03-01:

HPI Piggyback Issues, pending further

reviews of design documentation by the inspectors.

The licensee's actions with regard to potential inadequate ECCS flow

and HPI pump runout was to revise the EOP to restrict total HPI flow

during piggyback operation to less than 750 gpm, to require three

HPI pumps be operable during power operation and review of pump

runout flow requirements. The licensee's ECCS flow instrumentation

is air operated. The licensee's Instrument Air System is not safety

related, it is not seismically qualified and it does not meet single

failure criteria with respect to ECCS flow instrumentation. The

licensee's position is that these instruments fall under their

Regulatory Guide 1.97 commitments and will not fully meet safety

grade instrumentation requirements until the instruments are

modified to meet the Regulatory Guide 1.97 commitments previously

made to the NRC. The licensee is presently replacing these flow

instruments during the present Unit 3 refueling outage and stated

that the Unit 1 and Unit 2 instruments would be replaced during

their next scheduled refueling outages. The inspectors are

concerned with the extremely long time frame with respect to when

this instrumentation was identified as being deficient and the

schedule for correcting the deficiencies (over six years).

The

inspectors are also concerned with regard to the operability of the

ECCS systems due to the fact that this instrumentation must indicate

during an ECCS actuation. Further review of this issue is

identified as another example of Unresolved Item

50-269,270,287/91-03-01 discussed above.

5

d. Unit 3 Mid-loop Operations

The inspectors reviewed the licensee's actions with regard to

reducing RCS level to mid-loop operations. The licensee's

requirements for mid-loop operation are contained in Operating

Procedure (OP)3/A/1103/11: Draining and Nitrogen Purging of the RC

System. The procedure requires in part that the following items be

implemented prior to reducing RCS level below fifty inches as

indicated on reactor vessel level indicator LT-5:

-

A containment closure survey to identify containment

penetrations that would need to be closed in the event of a

loss of decay heat removal capability and to ensure that

containment closure can be achieved within 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />

-

Two independent RCS temperature indicators and alarms

-

LT-5 be operable and calibrated

-

Two LPI pump operable

-

Both main feeder buses are required to be energized and two

sources of electrical power are required to be available to

supply the main feeder buses

-

Two means of adding inventory to the RCS is required

-

Both steam generator upper primary side handhole covers removed

to provide a vent path

-

A review of maintenance and testing activities to ensure no

adverse effects on systems and components required for decay

heat removal.

The inspectors reviewed and witnessed the performance of portions of

procedure OP/3/A/1103/11. During the last Unit 2 refueling outage

the inspectors identified weaknesses in the conduct of the

licensee's actions with regard to mid-loop operations (NRC

Inspection Report 50-269,270,287/90-27). The licensee revised the

Unit 3 operating procedure since the Unit 2 refueling outage and one

of the major concerns identified has been resolved, ie: verification

of the proper operation of LT-5 prior to reducing RCS inventory to

less than eighty inches on the pressurizer level indicators. The

present procedure requires that at eighty inches pressurizer level

LT-5 agree within plus or minus five inches of indicated pressurizer

level.

When LT-5 was placed in service during the Unit 3 RCS

draindown it did not agree within five inches of pressurizer level.

Pressurizer level indicated approximately one hundred inches and

LT-5 indicated approximately eighty-five inches. The draindown was

stopped and the reactor vessel head vents were opened per the

procedure to obtain a better vent on the reactor vessel head region.

The licensee also checked LT-5 and no problems with the instrument

was identified. The licensee determined that the most logical cause

6

of the level mismatch was that the pressurizer was not properly

vented. The licensee decided to vent the pressurizer by breaking

the flange connection at the pressurizer power operated relief valve

(PORV). This corrected the level mismatch problem and the vessel

draindown was recommenced.

The licensee installed two ultrasonic level indicators on the RCS

prior to draining the RCS to less than fifty inches on LT-5. One

level detector was installed on a RCS hot leg and the other was

installed on a RCS cold leg. These level indicators indicate over a

very narrow range of RCS level ie: centerline of the hot and cold

leg to the top of the RCS hot and cold legs. The instruments

installed for this outage are scheduled to become permanently

installed indicators, provide indication via the plant computer and

provide a low level alarm in the control room. The licensee does

not consider that the installation and operability of the ultrasonic

level detectors are an absolute requirement for draining below fifty

inches. The inspectors consider that since LT-5 is the only wide

range level instrument below the level of the pressurizer level

instruments (approximately seventy-four inches) and the top of the

hot and cold legs (eighteen and fourteen inches) a second level

indication should be available to operators when operating in this

region. Discussions with the licensee determined that the addition

of another level indicator redundant to LT-5 is under consideration.

No violations or deviations were identified.

3. Surveillance Testing (61726)

a. General

Surveillance tests were reviewed by the inspectors to verify

procedural and performance adequacy. The completed tests reviewed

were examined for necessary test prerequisites, instructions,

acceptance criteria, technical content, authorization to begin work,

data collection, independent verification where required, handling

of deficiencies noted, and review of completed work. The tests

witnessed, in whole or in part, were inspected to determine that

approved procedures were available, test equipment was calibrated,

prerequisites were met, tests were conducted according to procedure,

test results were acceptable and systems restoration was completed.

Surveillances reviewed and witnessed in whole or in part:

PT/O/A/0400/15

SSF Submersible Pump Test

TP/O/B/28O/16

Turbine Overspeed Test

IP/O/A/4980/51A/RE Westinghouse Type CO-5, CO-6, CO-7, CO-8

and CO-11 Relay Test

PT/O/A/0160/06

RBCU Heat Exchanger Performance Test

7

b. Safety Related Procedures Past Due Their Two Year Review

On January 9, 1991, the licensee discovered that 50 safety related

procedures were past due their two year periodic review. Following

the discovery, the procedures were immediately put on administrative

hold, thereby enabling the procedure to be reviewed prior to use in

the field. This problem was identified during a review of the

computerized index of the I&E procedures. Duke Power Company

Administrative Policy Manual requires a comprehensive periodic

review of all station procedures at intervals not to exceed two

years for safety related, and not to exceed five years for non

safety related procedures to ensure adequacy of the procedure.

Normally, the periodic review schedule is tracked closely, and

procedures that have their reviews coming up are either reviewed or

put on administrative hold before the review due date. During the

1986-1987 time frame, a significant backlog developed on procedures

that were on administrative hold and were pending a review. The

procedure supervisor released the procedures awaiting the two year

review from administrative hold. Subsequently, the concept of

administrative hold lost significance and resulted in safety related

procedures not being reviewed at the required two year interval.

This is identified as a Non-cited Violation 50-269,270,287/91-03-03:

Failure to Periodically Review Safety Related Procedures at Intervals

Not to Exceed Two Years. This licensee identified violation is not

being cited because criteria specified in Section V.A of the NRC

Enforcement Policy were satisfied.

No additional violations or deviations were identified.

4. Maintenance Activities (62703)

a. General

Maintenance activities were observed and/or reviewed during the

reporting period to verify that work was performed by qualified

personnel and that approved procedures in use adequately described

work that was not within the skill of the trade. Activities,

procedures, and work requests were examined to verify; proper

authorization to begin work, provisions for fire, cleanliness, and

exposure control, proper return of equipment to service, and that

limiting conditions for operation were met.

Maintenance reviewed and witnessed in whole or in part:

WR 57518A

PM On 3TC-10 RBS Motor 3A Circuit Breaker

WR 57516A

PM On HPI 3A Motor Circuit Breaker

WR 52607

Disassembly, Inspection and Repair of 3MS-95

WR 52608J

Disassembly, Inspection and Repair of 3MS-94

WR 57115D

Perform PM On Turbine Driven Emergency Feedwater

Pump Turbine

WR 57064D

Clean Tube Side of Component Cooler 3B

WR 57514A

Perform PM on Breaker 3TC-6

8

WR 57461B

Perform PM on 5X-51X, 50Z-51Z and 50G Relays

in 3TC-8

WR 55304B

Replace Peak Filtering Capacitor in RPS Power

Suppl ies

WR 50671K

Votes Testing of 3LPSW-19

WR 52897J

Determine Valve Position Upon Loss of IA for

3MS87

WR 52854J

Determine Valve Position Upon Loss of IA for

3FDW-315

WR 054981

Installation of 6th Stage Impeller in the 3A

MDEFWP

IP/0/A/305/13 Nuclear Instrument and RPS Power Supply

Capacitor Replacement

MP/0/A/2001/3 Air Circuit Breaker Inspection and Maintenance

MP/3/A/1300/28 Motor Driven Emergency Feedwater Pump

Impeller Changeout

b. Reactor Protection System Power Supply Preventive Maintenance

The inspector observed a portion of the work activity associated

with WR 55304B, replacement and testing of the RPS power supplies

peak filtering capacitor. The preventive maintenance is performed

every third refueling outage and is accomplished by IP/O/A/305/13,

Nuclear Instrument and Reactor Protective System Power Supply

Capacitor Replacement. The inspector observed the I&E technicians

reterminating the power supply leads in the back of the RPS cabinet

prior to repowering the power supplies. Review of the controlling

procedure determined that the procedure did not control the lifting

or retermination of wires lifted by the technicians to remove and

reinstall the RPS power supplies. The technicians did not have any

documentation that identified the leads that had been lifted to

remove the power supplies and did not have any documentation that

the leads were properly reterminated. The inspector did observe

that the wires did have blue tags attached to them. The procedure

did require that a QA inspector verify that the power supplies had

been reinstalled; however, this step had already been signed off by

the QA inspector and the technicians were still reconnecting the

wires in the back of the RPS cabinet. Discussions with the

technicians determined that the QA inspector had signed only for the

power supplies being installed in the proper cabinet. Maintenance

Directive 7.5.3, Work Request Implementation, requires that

Section V of the work request "Additional Sheet" be completed

anytime temporary alterations are made to plant equipment or circuit

configurations and that the disconnection/reconnection of wiring be

listed. The Maintenance Directive also requires the date and time

the wires were disconnected/reconnected be entered, that the persons

performing the disconnection/reconnection sign each time when they

have performed the operation and that the two independent

verifications of the action be documented. The failure to meet the

requirements of Station Directive 7.5.3 with respect to

8

WR 57461B

Perform PM on 50X-51X, 50Z-51Z and 50G Relays

in 3TC-8

WR 55304B

Replace Peak Filtering Capacitor in RPS Power

Supplies

WR 50671K

Votes Testing of 3LPSW-19

WR 52897J

Determine Valve Position Upon Loss of IA for

3MS87

WR 528543

Determine Valve Position Upon Loss of IA for

3FDW-315

WR 054981

Installation of 6th Stage Impeller in the 3A

MDEFWP

IP/0/A/305/13 Nuclear Instrument and RPS Power Supply

Capacitor Replacement

MP/0/A/2001/3 Air Circuit Breaker Inspection and Maintenance

MP/3/A/1300/28 Motor Driven Emergency Feedwater Pump

Impeller Changeout

b. Reactor Protection System Power Supply Preventive Maintenance

The inspector observed a portion of the work activity associated

with WR 55304B, replacement and testing of the RPS power supplies

peak filtering capacitor. The preventive maintenance is performed

every third refueling outage and is accomplished by IP/0/A/305/13,