ML20235W216

Insp Repts 50-324/89-02 & 50-325/89-02 on 890101-31. Violations Noted.Major Areas Inspected:Maint Observation, Surveillance Observation,Operational Safety Verification, Flow Restricting Orifices & Onsite LER Review

ML20235W216
Person / Time
Site:	Brunswick
Issue date:	02/27/1989
From:	Levis W, Madden P, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20235W199	List: ML20235W196 ML20235W205 ML20235W216
References
50-324-89-02, 50-324-89-2, 50-325-89-02, 50-325-89-2, NUDOCS 8903100549
Download: ML20235W216 (22)

See also: IR 05000324/1989002

Text

'

'

e .. ,.)' '

UNITED STATES s ,

[pm Reog].o NUCLEAR REGULATORY COMMISSION

0

[A ' ,$ R EGION 11

.g J j '> 101 M ARIETT A STREET, N.W.

• • \ "y ATLANT A, GEORGI A 30323

g vr.....f

Report Nos. 50-325/89-02 and 50-324/89-02

1

Licensee: Carolina Power and Light Company

P;'0. Box 1551

Raleigh, NC 27602

Docket Nos. 50-325 and 50-324 Licensa Nos. DPR-71 and DPR-62

Facility Name: Brunswick 1 and 2

Inspection Conducted: January 1-31, 1989

Inspector: h

W,'H. Ruland

-e I Uh

Date Signed

r7'

'

^^ ^W > YN

W. Levis V r. Date Signed

^

n:

r

Uhf

Date Signed

P. M. adden f'

Approved by: C h 27!fE

. C. Dance, Section Chief Date Sidned

Division of Reactor Projects

-

SUMMARY  !

Scope: This routine safety inspection by the resident inspector' involved the

areas of maintenance observation, surveillance observation,

operational safety verification, flow -restricting orifices', onsite

Licensee Event Reports (LER) review, in office LER ' review, followup

C on Temporary Instruction (TI) 2500/20 - implementation of the ATWS

l

rule, onsite followup of events, Onsite Nuclear Safety. (0NS) group,

and action on previous inspection findings . 1

Results: In the areas inspected, two violations were identified: (1) operator

inattention to detail led to inadequate implementation of a clearance

on the 2A RHR pump, paragraph 11.d; and (2) design requirements for

,

flow restricting orifices were inadequately specified. The orifice

l

plates, as originally designed, were too thin for their application.

The licensee found them deformed from the flow, paragraph 5. This

violation was 'found to meet the intent of the criteria specified in l

l Section V of the NRC Enforcement Policy for not issuing a Notice of

Violation.

Two unresolved items were also identified: (1) inadequate work

. control and clearance led to the partial dra' in g of the Unit 1 SLC

8903100549 090227

PDR ADOCK 05000324 i

o PNV l

-

. ]

, _ _

.. .

.

b

,

-

2

0

.ec

.

tank : during'. refuel ' operations, paragraph ~ 4.b;' 'and (2) ' inadequate

control of raceway. electrical physical.' separation,. paragraph 4.c. In

.

addition, a standby gas treatment system periodic test was identified

. asL- needing' clarification regarding the acceptance criteria,.

. paragraph 3.

The -licensee' has implemented, and is continuing to implement--a plan

to comply with the ATWS-rule. .To date,-there are still-three issues

that need to be accomplished, paragraph 8.

l

,

_ . _ . . _ _ _ _ _ _ _ . _ _._ ._____m___________m - _ _ _ _ _ _ _ . _ . _ _ _ _ _ __ _ _ _ _ _ _ J

o

, .

.

.

REPORT DETAILS

1. Persons Contacted

Licensee Employees

• K Altman, Manager - Maintenance

W. Biggs, Engineering Supervisor

• F. Blackmon, Manager - Operations

• J. Brown, Res. Engineer

• S. Callis, On-Site Licensing Engineer

T. Cantebury, Mechanical Maintenance Supervisor (Unit 1)

• G. Cheatham, Manager - Environmental & Radiation Control

R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)

W. Dorman, Supervisor - QA

• K. Enzor, Director - Regulatory Compliance

• R. Groover, Manager - Project Construction

• J. Harness, General Manager - Brunswick Nuclear Project

W. Hatcher, Supervisor - Security

A. Hegler, Supervisor - Radwaste/ Fire Protection

• R. Helme, Manager - Technical Support

• J. Holder, Manager - Outages

• L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)

• M. Jones, Director - On-Site Nuclear Safety - BSEP

R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)

G. Oliver, Manager - Site Planning and Control

• J. O'Sullivan, Manager - Training

B. Parks, Engineering Supervisor

• R. Poulk, Project Specialist - NRC

J. Smith, Director - Administrative Support

• R. Starkey, Project Manager - Brunswick Nuclear Project

V. Wagoner, Director - IPBS/Long Range Planning

R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)

B. Wilson, Engineering Supervisor

• T. Wyllie, Manager - Engineering and Construction

Other licensee employees contacted included construction craftsmen,

engineers, technicians, operators, office personnel, and security force

members.

• Attended the exit interview

Note: Acronyms and initialisms used in the report are listed in paragraph

13.

2. Maintenance Observation (62703)

The inspectors observed maintenance activities, interviewed personnel, and

reviewed records to verify that work was conducted in accordance with

approved procedures, Technical Specifications, and applicable industry

_ - __- _ _ -

,__ _ _ _ _ _ . . _ _ . __ ,_ _ _ _ _ . _ _ _ _ . ____ _ _ _ _

F =

l

.

, I

,

'

2

codes and standards. .The inspectors also verified that: redundant

components were operable; administrative controls were followed; tagouts

were adequate; personnel were qualified; correct replacement parts were

used; radiological controls were proper; fire protection was adequate;

quality control hold points were adequate and observed; adequate

post maintenance testing was performed; and independent verification

requirements were implemented. The inspectors indeperidently verified that

selected equipment was properly returned to service.

Outstanding work requests were reviewed to ensure that the licensee gave

priority to safety-related maintenance. The inspectors observed / reviewed

portions of the following maintenance activities:

87-AYRB2 Installation of Fire Pump Packing Sleeves

88-BCBE2 2A Emergency Filtration Fan 2-VA-2A-ERF-CB Thermal Overload

Problem

88-'BGYT1 Cable Coatings Service Water Structure

89-ABIR1 Cable Coatings Diesel Generator Basement

PM-88-003 Hydrogen Gas Line Replacement Temporary Line

No violations or deviations were identified.

3. Surveillance Observation (61726)

The inspectors observed surveillance tecting required by Technical

Specifications. Through observation, interviews, and record review, the

inspectors verified that: tests conformed to Technical Specification

requirements; administrative controls were followed; personnel were

qualified; instrumentation was calibrated; and data was accurate and

complete. The inspectors independently verified selected test results and

proper return to service of equipment.

The inspectors witnessed / reviewed portions of the following test

activities:

IMST-APRM25Q APRM E Channel Calibration / Functional Test

2MST-HPCl22M HPCI Steam Line Low Pressure Instrument Channel

Calibration

2MST-HPCI23M HPCI Turbine Exhaust Diaphram High Pressure Instrument

Channel Calibration

2MST-RHR27M RHR Shutdown Cooling Reactor Pressure Instrument Channel

Calibration

_ - - _ _ _

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

, .

.

-

l

3

During a review of the Unit 2 C0 and SF logs on January 24, 1989, the

inspector noted that, during the performance of PT-15.6, the monthly SBGT

Operability Check, train 2A experienced erratic flow indications several

hours into the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> test. Despite the flow indication problem,

operations accepted the PT as satisfactory; however, train 2A was declared

l inoperable. Maintenance repaired the flow indicator and train 2A was run

for approximately 15 minutes to verify that it worked properly. The

inspector questioned the licensee on two aspects of this event.

First, it was not clear that the PT should have been accepted as

satisfactory. The acceptance criteria of PT-15.6 consists of two parts:

(1) Criterion 6.0.1.1 requires that SBGT systems operate for at least 10

hours with flow through the charcoal adsorbers and HEPA filters with the

heaters in automatic control . (TS 4.6.6.1.a requires that this be done

every 31 days.); and (2) Criterion 6.0.1.2 requires that the pressure drop

across the HEPA filters and charcoal adsorbers be less than 8.5" at a flow

rate between 2700 and 3300 scfm. (TS 4.6.6.1..d.1 requires that this

system parameter be verified every 18 months.) When the flow and D/P

values were recorded on the PT data sheets, the above parameters were ,

l

indicating in the proper band. The fact that the flow indication later

became erratic was never documented on the PT.

The second aspect questioned by the inspector was the acceptability of a

15 minute run to check the flow indicator after repairs. The inspector

noted that it had taken several hours for the indicator to fail previously

and was not sure that 15 minutes was adequate to verify operability. The

inspector felt that the licensee should have stopped the PT at the point

the indicator became erratic, repaired the indicator, then reperformed the

PT.

Based on the inspectors questions, the licensee determined that the PT did

not meet the acceptance criteria and, therefore, was unsatisfactory. The

licensee then repeated the PT. The flow indicator failed shortly after

starting the test. The indicator was again repaired and the PT completed

satisfactorily.

The inspector reviewed the TS surveillance requirements for SBGT. The

inspector determined that no violation of the SBGT TS surveillance

requirements occurred. TS 4.6.6.1.6.3 requires verification of 3000 scfm  ;

flow every 18 months and had been verified the previous month during the

performance of PT-15.6. In addition, the licensee made no alterations to

the SBGT system to change flow. The valve lineup was the same, the fan

motor was still running and the proper D/Ps existed across the HEPA

filters and charcoal adsorbers. However, a procedural deficiency exists

in PT-15.6. The data recorded on the PT data sheets indicated that the PT

was completed satisfactorily with no problem noted concerning the flow

indication. Operations issued Item of Concern 89014-01 to address this

issue. The inspector will monitor the licensee's closeout of this item in

future routine inspections.

No violations or deviations were identified.

1

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

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

, 4

.

'

.

4

4. Operational Safety Verification (71707)

The inspectors verified that Unit 1 and Unit 2 were operated in compliance

with Technical Specifications and other regulatory requirements by direct

observation of activities, facility tours, discussions with personnel,

reviewing of records, and independent verification of safety system

status.

The inspectors verified that control room manning requirements of 10 CFR l

50.54 and the Technical Specifications were met. Control operator, shift  !

supervisor, clearance, STA, daily and standing instructions, and jumper /  ;

bypass logs were reviewed to obtain information concerning operating l

trends and out of service safety systems to ensure that there were no.

conflicts with Technical Specification Limiting Conditions for Operations.

Direct observations were conducted of control room panels. instruments-

tion, and recorder traces important to safety in order to verify ,

operability and that operating parameters were within Technical i

Specification limits. The inspectors observed shift turnovers to verify

that continuity of system status was maintained. The inspectors verified i

the status of seiected control room annunciators. .

I

Operability of a selected Engineered Safety Feature division was verified

weekly by ensuring that: each accessible valve in the flow path was in  ;

its correct position; each power supply and breaker was closed for

components that must activate upon initiation signal; the RHR subsystem

cross-tie valve for each unit was closed with the power removed from the

valve operator; there was no leakage of major components; there was proper  ;

lubrication and cooling water available; and a condition did not exist I'

which might prevent fulfillment of the system's functional requirements.

Instrume1tation essential to system actuation or performance was verified

operaME ' by observing on-scale indication and proper instrument valve-

lineup, if accessible.

The inspectors verified that the licensee's health physics policies /

procedures were followed. This included observation of HP practices and a

review of area surveys, radiation work permits, posting, and instrument ,

calibration. l

!

The inspectors verified that: the security organization was properly  ;

manned and security personnel were capable of performing their assigned

functions; persons and packages were checked prior to entry into the

protected area; vehicles were properly authorized, searched and escorted

within the PA; persons within the PA displayed photo identification

badges; personnel in vital areas were authorized; and effective

compensatory measures were employed when required.

The inspectors also observed plant housekeeping controls, verified

position of certain containment isolation valves, checked a clearance, and

verified the operability of onsite and offsite emergency power sources.

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ l

_ _ _ _ - - _

g -

t.

-

r

s

'

5

a. Adequacy of SRM Channel Check

The licensee began reloading the Unit I core on January 18, 1989.

Shortly after beginning' their reload, the licensee experienced two

problems with SRMs. After loading fuel bundles around SRM B, no

indication was noted. The SRM B was declared inoperable and

subsequent troubleshooting revealed a. problem with the preamplifier.

The'next day, a problem was found with the control roon indicator for

SRM D. The meter had drifted out of calibration and was subsequently

recalibrates.

The inspector questioned why the channel functional test for the

SRMs, which is required to be accomplished 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to core

alterations, did not find these problems. The licensee had performed

1 MST-SRM11W, SRM Channel Functional Test, to satisfy the Technical

Specification requirement prior to moving fuel. The licensee plans

to resolve the inspector's questions prior to the end of the next

inspection period.

b. Inadvertent Draining cf SLC Tank -

Unit I demineralized water supply valves leaked by, diluting the

boron concentration in the SLC tank. The leakage worsened, and SLC

was declared inoperable on January 27, 1989, due to insufficient

boron concentration in the tank. The licensee drained several

hundred gallons from the tank, added chemicals to bring the

concentration within TS requirements, and initiated a work order to

repair the leaking valves.

There are two possible sources of leak-by of demineralized water to

the SLC tank. One source is leakage past the F010 valve, the normal

SLC tank fill valve, and the other is F014, the SLC test tank outlet

demineralized water supply valve. These valves are normally locked

closed. Clearance 1-189 was issued for work on the F010 valve.

After the clearance was hung, maintenance personnel signed the

clearance, indicating that they concurred with the clearance.

Maintenance also requested authorization for two work orders, one to

repair the F010 valve, and one to repair the F014 valve. The SF

authorized work on both valves, thinking that both valves were under

clearance. A different SF had approved the clearance.

After the work was authorized, maintenance personnel began repairs.

They noted that both valves, F010 and F014, were locked closed. They

called the control room concerning this condition and received

permission from operations to remove the locking devices and open the

valves. After the valves were opened, the maintenance personnel

loosened the bonnet bolts for both valves. Leakage was noted to come

from the valves' bonnet area. After about 15 minutes, the leakage

had not stopped. Since no leakage was coming from the drain valves

1

i

l

. - _ _ _

1

x c

.

.

4 6

intended to drain the demineralized water header, the maintenance

personnel -informed the control room. The operations personnel

assumed that the leakage was from the demineralized water header and

told ' maintenance that the leakage was expected. The . operations

personnel .were unaware that the previous shif t had already drained

the header in preparation for work on the F010 valve. Unknown to

operations, water was draining from the SLC tank, .through the open

SLC suction valve, F001, and then out the bonnet area for the F010

and F014 valves. The inadvertent draining of the SLC tank co.itinued

for about one hour and a half until the SLC tank low level alarm was

received at 3200 gallons. Operations reviewed the clearance for the

work, recognized the error in the clearance, and'had maintenance stop

work.

While the SLC tank was being inadvertently drained, the licensee was

withdrawing and then inserting control rods one at a time for timing

purposes. Technical Specification 3.1.5 requires that the SLC be

operable when in operational condition 5 (refuel) and, with the SLC

system inoperable, all operations involving core alterations or

positive reactivity changes must be .2 pended and all insertable

control rods must be inserted within one hour. The licensee believes

that the SLC system was operable during this inadvertent draining

event. Their documented operability assessment was not completed by

the end of the inspection period. Pending review of the licensee's

operability assessment, this will be an " Unresolved Item:

Inadvertent Draining of the SLC Tank (325/89-02-03).

The inspector concluded that, at a minimum, the clearance and work

controls in effect for work on these valves was inadequate. Had the

work been for the F010 valve only, the clearance would still have

been inadequate. The F014 valve should have been tagged closed to

allow work on the F010. The lack of adequate work controls,

specifically related to inadequate or improper clearances during

outage periods, is a recurring problem at Brunswick. Recently, as

documented in inspection report 88-45, an improper clearance rendered

the secondary containment isolation dampers inoperable. This problem

was addressed in an enforcement conference held on January 13, 1989.

As part of the corrective action, the licensee now requires a second

SR0 to review clearances affecting safety systems. This corrective

action was in place wnen the SLC clearance was authorized. This

matter was discussed with licensee management and will be further

addressed in the followup of the unresolved item.

• Eresolved items are matters about which more information is required to

-determine whether they are acceptable or may involve violations or

deviations.

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

, - .

7

c. Missing Cable Tray Covers

The inspectors, as a part of their routine walkdown, inspected the

area over the battery rooms in the Unit 2 cable spreading room. The

inspectors noted two cases where the physical electrical separation l

requirements of plant specification 048-004, Design and Installation

of Raceway System and Isolation and Separation of Interconnecting

Wire and Cable, revision 12, section 2.2.2, paragraph 2.2.2.4.c and

d, may not have been met.

The first concern involves the divisional intersection of trays

56M/DA (Division I) and 54M/DB (Division I). These trays cross one

another and do not have the minimum 18-inch spatial separation

between the divisionalized cable tray networks and they are not

provided with metal tray covers as required by the specification.

The second concern involves the spatial separation provided between

cable pull box WM7 (Division II) and cable tray 93K/CA (Division I)

and compliance with the specification. The licensee has not

demonstrated that they have adequate controls in place to assure that

the physical electrical separation design configuration required by

the subject specification is being maintained: Tne inspector

requested that the licensee supply the necessary documentation to

demonstrate that controls are in place to maintain the physical

electrical design configuration as required by specification 048-004.

The inspector's final resolution of this issue will be made pending

the review of this documentation. This item remains Unresolved:

Inadequate Control of Electrical Physical Separation Provided for

Divisionalized Raceway (325/89-02-04 and 324/89-02-04).

No violations or deviations were identified.

5. Flow Restricting Orifices (62703)

The licensee found several flow restricting orifices deformed in the RHR,

HPCI, RCIC, and Core Spray systems of Unit 1. Based or, erosion problems

found with certain RHR valves late last month, the licensee started to

inspect both flow restricting orifices and flow measuring orifices for

possible erosion damage. While no erosion damage was found, several flow

restricting orifices were found deformed in the direction of flow.

Damaged safety related orifices included:

RHR Minimum Flow E]1-FO-D001B (A,C,D)

Core Spray Min Flow E21-FO-D001A (B)

Core Spray Injection E21-FO-D002A (B)

HPCI Minimum Flow E41-FO-D005

HPCI Full Flow Test E41-FO-0010

_ _ _ _ -

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

_ _ _ _ _ _ _ _ ,

., [ c .-

-\

p .

y

'

,

8

RCIC Minimum Flow E5'l-FO-D005

l

l- RCIC Full Flow Test E51-F0-D006

.

Note: The letters in parentheses indicate other division orifices of ~

similiar design that were not inspected.

Technical Support predicted the failure of the above orifices considering

plastic deformation of the stainless steel plates. All of 'the above

orifice plates were 1/8" A240-316 stainless steel. Liquid penetrant

testing of the plates showed no cracking in spite of applied stresses

exceeding several ._ times the yield stress of' the material . The worst case

deformation occurred in the HPCI min flow orifice. The pipe ID was 3.83"

and the orifice bore originally was 1.021". The licensee found.the bore

had increased to 1.088" and the plate had ballooned out about'1/2".

The licensee replaced the above Unit 1 orifice plates with locally

manufactured plates that met the correct design requirements. However,

the Core Spray injection orifice plates, while increased to 1/4", should

be .36" based on the licensee's design rules for the other orifices.

Several EERs document the replacement of the orifice plates and justify

continued operation of Unit 2, the operating unit. EER 89-0013 assessed

operability of the Unit 2 orifice plates. The enginering staff found that

continued Unit 2 operation was acceptable because:

o Material properties of the stainless steel after yielding

(effectively cold working the steel) resist further deformation.

o If they failed, the orifice failure mode would be tearing, since the

stainless steel will behave ductilely as indicated above; thus, no

loose parts concern exists.

,!

o Unit 1 inspections confirmed the above statements.

o Increased orifice sizes found or Unit I have been reviewed and have

no significant effect on system operation.

The licensee also accepted operation of the Unit I core spray systems with

the 1/4" plate till the next refueling outage. The orifice plates will be

inspected and/or replaced as necessary after that inspection.

The plates deformed because of inadequate original design and ,

specification. A reference in the original design specification supplied '

minimum values for orifice plate thickness based on measurement devices.

Those plates normally have low differential pressures. No evaluation or

calculations were performed for plates which did not have minimum

differential pressures, namely, the flow restricting orifices.

The licensee failed to take an opportunity in 1982 to discover this

problem. Maintenance found a damaged HPCI full flow test orifice plate in

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

,

C .

.

'

'

.

9

December 1982 (WR&A 1-M-82-387). The plate was replaced in June 1985

without an engineering review being performed to determine the root cause

of the failure. This failure to adequately correct a problem with safety

related equipment is a failure to fully implement the licensee's quality

assurance program. However, since the licensee has undergone extensive

upgrade in program and organizational changes since that failure was

missed, and the licensee found and underwent extensive actior, to correct

the problem, this is considered to be a licensee identified violation:

Inadequate Design of Flow Restricting Orifice Plates (325/89-02-02 and

324/89-02-02). Accordingly, as this violation meets the intent of the

criteria specified in Section V of the NRC Enf orcamnet Policy for not

issuing a Notice of Violation, its not being cited

The inspectors examined an orifice plate, interviewed the responsible

engineer, and reviewed documentation and engineering evaluations related

to this issue. Based on the inspection scope and the information

provided, the inspectors conclude that the licensee adequately addressed

the issue. Future routine inspection will be performed in the area to i

i

verify that the Unit 2 orifice plates are replaced as the licensee

indicated. .

One violation was identified.

6. Onsite Review of Licensee Event Reports (92700)

The below listed LERs were reviewed to verify that the information

provided met NRC reporting requirements. The verification included

adequacy of event description and corrective action taken or planned,

existence of potential generic problems and the relative safety

significance of the event. Onsite inspections were performed and

concluded that necessary corrective actions have been taken in accordance

with existing requirements, licensee conditions, and commitments.

a. (CLOSED) LER 1-87-21, Unit 1 Primary Containment Groups 2, 3, and 6

Isolations and B Logic Signal Due to Inadvertent Deenergizing of

Units 1 and 2 Common Emergency AC Bus E2. The licensee determined

that this event resulted from the installation activities associated

with the Emergency Response Facility Information System. In response

to this event, the licensee conducted a review of all remaining ERFIS

computer points to be installed to determine if any additional safety

precautions with regard to manipulation of energizea leads were

required. In addition, the licensee committed not to install any

ERFIS computer points involving voltage monitoring of the emergency

buses whenever the respective standby DG is unavailable.

The inspector reviewed the ERFIS computer tie-in documentation

associated with plant modification PM-84-340-T, ERFIS Tie-In to

Electrical Batteries / Distribution System, and PM 85-061-T , ERFIS

Tie-In to Electrical Distribution System. For the modifications

reviewed, the licensee did not perform any ERFIS tie-ins to the

emergency buses while the respective DG set was out of service. In

_ _ _ _ _ -

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

_- -- __- . -

l* .

+

'

.

.

10 h

1

l

addition, the inspector verified that the licensee conducted a review

of ERFIS plant. modifications to determine if any additional safety-

precautions regarding manipulation of energized leads were required.

The licensee concluded that additional precautions were required to

be incorporated into PM 84-340-V, ERFIS -Tie-In to ~ Containment

Atmosphere Control, PM 85-061-T, ERFIS Tie-In to the Electrical-

Distribution System, and PM 84-340-T, ERFIS Tie-In to the Batteries /

Electrical System. The inspector reviewed these precautions and

found them acceptable.

b. (CLOSED) LERs 1-87-23, Inoperability of HPCI System Due to Failure

of- HPCI Turbine Steam -Inlet Isolation Valve E41-F001; 1-88-11,

'

Inoperability of HPCI System. Resulting from Failure of HPCI Pump

Suppression Pool Supply Outboard Isolation Valve; 1-88-12,

Inoperability of High Pressure Coolant Injection System Due to

Failure of HPCI Turbine Steam Inlet Isolation Valve During-

Operability Testing; 1-88-17, Inoperability of HPCI System Due to

Failure of HPCI Turbine Steam Inlet Isolation Valve During Opera-

-bility Testing; and 1-88-19, Inadequate Design of High Pressure

Coolant Injection Pump Discharge Valve.

The above LERs dealt with the inoperability of the Unit 1 HPCI system

due to valve failures or potential valve failures caused by design -

deficiencies. Due to the numerous problems experienced with the HPCI

MOVs, the licensee createct a task group to determine the design

operating margin of each safety related MOV and to evaluate' each

valve with respect to 'the postulated environmental and degraded

voltage scenarios. Some of the concerns to be evaluated by the task

group include the following:

o Use of starting resistors in motor starting circuits.

o Temperature effects on motor torque.

o Evaluation of cable sizing.

o Installing surge protection within shunt coil circuitry.

o Usc of double disc versus flex wedge disc gate valves.

o Relocation of valves to less harsh environments.

o Changing gearing of actuators.

Several of these deficiencies, along with corrective actions taken to

date, have been inspected previously as detailed in inspection

reports 88-21, 88-24 and 88-27. Based on these inspections, the

inspector will close the above LERs. However, the inspector will

followup on the results of the licensee's valve task group and any

required corrective action. This will be an Inspector Followup Item:

Followup on Valve Task Group Findings (325/89-02-05 and 324/89-02-05).

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

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

.c~ . .  ;

O

'

-

J

11

'

,

-c. (CLOSED) LER 1-88-18, Inoperability of HPCI System Pump ~ Suppression.

Pool Suction Supply Outboard Primary.- Containment Isolation Valve.

The inspector reviewed licensee activities related to the subject LER

and. associated' corrective actions to prevent recurrence. At the time

of the incident, the inspector also examined the. limit switch

subassembly and verified that there was a bent finger. in the finger

assembly, along with some . slight charring of. the rotor insert,

indicating intermittent electrical contact between the finger and

rotor insert. The cause of the bent finger in the assembly was

attributed to personnel error. The licensee. had recently started ,

'

cleaning limit . switch contacts as part of their routine preventive

maintenance program due to two previous valve failures attributed to

'

dirty limit switch contacts (see Inspection Report 88-18). As part

of their corrective action, the licensee inspected 22 other valves

which had previously been inspected under their new maintenance

instructions governing ' limit switch contact cleaning. No other

problems were noted. In addition, the licensee provided additional

- instructions in MI-10-25, Rev. 3, dated November 9, 1988, for the

method of cleaning contacts along with precautions.for handling of

limit switch fingers. -The gap between the finger assembly and finger

spring guide are now also checked as part of the revised procedure.

No violations or deviations were identified.

7. In Office Licensee Event Report Review (90712)

The below listed LERs were reviewed to verify that the information

provided met NRC reporting requirements. The verification included

adequacy of event description and corrective action taken or planned,

existance of potential generic problems and the relative safety

significance of the event.

(CLOSED) LER 1-88-29, Control Building Emergency Air Filtration System

Isolation Due to a Loss of Power to the Chlorine Detectors in the Service

Water Building.

(CLOSED) LER 2-88-20, RWCU Isolation During a HPCI MST Due to a Spurious-

Actuation of Riley Temperature Switches in the Steam Leak Detection

System. l

(CLOSED) LER 2-88-21, Primary Containment Group 3 Isolation Resulting

from Unplanned Actuation of RWCU Area High Temperature Switch G31-TS-N600C.

No-violations or deviations were identified.

8. Followup on TI 2500/20 (25020)

(OPEN) TI 2500/20, Inspection to Determine Compliance With ATWS Rule,

10 CFR 50.62. The purpose of this inspection was to determine if the

licensee has implemented their program as previously committed to NRC for

complying with 10 CFR 50.62, the ATWS rule. In addition, some program

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

---_

.-:.

.

-

e

12

l

,

elements were inspected to verify that quality controls were adequate

' during the design, installation and subsequent testing 'of the system. To

comply with the ATWS rule, the licensee modified their existing SLC system

and Recirculation Pump Trip system and added the Alternate Red Injection

system. A summary of the changes to each of these systems is provided

along with a discussion of other functional arecs inspected.

SLC

The SLC' system was modified for both units to allow for 2 pump injection.

86 GPM of 13 weight percent of sodium pentaborate is specified in the-

rule. Based on an equivalency determination performed by the licensee due

to their smaller reactor vessel (218" ID versus 251" ID), the Brunswick

injection rate required is 66 GPM of.13 weight percent sodium pentaborate.

The equivalency methodology used by the licensee was accepted by NRR in an

SER dated October 21, 1986. The plant's Technical Specifications for each

unit have been changed to show a different relief valve setpoint,

different allowable volume / concentration levels for the sodium pentaborate,

and also to specify a one pump injection requirement of 41.2 GPM. The

Safety Evaluations which accepted these changes are dated April 16, 1987,

and January 28, 1988, for Unit 1 and Unit 2, respectively.

ARI

The purpose of the ARI system is to initiate a reactor scram by a means

independent of the RPS system. To accomplish this, four additional vent

paths have been installed in the RPS scram pilot valve air header. Each

vent path consists of two solenoid valves in series. The location of the

four sets of solenoid valves is as follows:

o Upstream of backup scram solenoid valves,

o Scram Discharge Volume vent and drain air line.

o South bank Hydraulic Control Units.

o North bank Hydraulic Control Units.

The solenoid valves are normally deenergized. When an actuation signal is i

received from the ARI logic, the solenoid valves energize and reposition l

to vent air from the scram pilot valve air header to vent the control rods

and close the SDV vent and drain valves. Rod motion is required to begin

within 15 second and be completed within 25 seconds.

The ARI logic consists of two logic systems. Each logic system consists l

of two low reactor water level instrumentation channels in series and two

reactor pressure instrumentation channels in series. The logic system

receives a trip signal if both of the associated level channels or

pressure channels trip. The setpoints for the level and pressure j

instrument trips are set such that a reactor scram signal should have

already been sensed by the RPS system. The logic is designed such that it

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

. - . ____--___ _____ _ -_ - __

.. ..

.

.

p- 13

is testable at power. Only one logic. system will be inoperable during

testing. A valid signal sensed by the other logic system will still 'cause

an ARI. This' system is installed on Unit 2 and is currently being -

installed on Unit 1 during the refueling outage.

! NRC accepted the licensee's ARI design, with exceptions, in SERs dated

September 18, 1987, and April 8, 1988. The September 18, 1987 SER noted

problems with the testability feature of the system; which the licensee

corrected. The April 8, 1988 SER noted a problem related to the diversity

of the ARI system from RPS. Specifically, the sensors used by the ARI.

system to measure pressure and level are Rosemount analog transmitters /

trip units. These same signal conditioning devices are also used in RPS. j

NRC stated that sufficient diversity did not exist and that the licensee

design was not in compliance with the rule. A one cycle extension was

given for Unit 2 in the issuance of Amendment 150 dated April 8, 1988.

While inspecting the installation of the ARI solenoid valves, the.

inspector noted the following:

Manufacturer, model number, energization stote, and power source (DC)

are identical for the backup scram solenoid valves and for ARI

solenoid valves which are redundant to the backup scram solenoid

valves.

Manufacturer and model number are the same for ARI and RPS SDV vent

and drain solenoid valves.

Manufacturer for individual scram solenoid valves are the same as ARI

solenoids on HCU banks. ,

The inspector discussed the above findings with NRR. NRR concluded that

this was sufficient diversity since the individual scram solenoids were of

a different mcdel, energization state, and power source than the ARI

solenoid valves located on each HCU bank. In addition, failure of the

solenoids for the SDV vent and drain valves would not prevent rod

insertion or the successful completion of the scram valves. Diversity of

the ARI solenoid valves from the backup scram valves was not a

requirement.  !

The inspector also reviewed the electrical independence of the ARI system

from RPS. The inspector noted that the ARI logic and solenoid valves were

powered from the same distribution panel as one division of RPS analog

transmitters / trip units. This matter was brought to the attention of NRR

for resolution.

RPT

i

The recirculation pump trip is supplied from the same logic that supplies

the ARI system. A trip of either logic system will cause both recircula-

tion pumps to trip. The Brunswick design utilizes one trip coil which

4

)

_ _ _ _ - _

~ .

.

!

I

14

I

trips the feeder breaker to the recirculation pump motor generator set. I

This design is different from the Hatch or Monticello design approved by j

NRC in an SER dated October 21, 1986. Approval of BSEP design is still i

under consideration by NRR.

E i

The inspector reviewed QA/QC involvement with the licensee's

implementation of the ATWS rule. The inspector verified that design

control measures, procurement control, and receipt instructions were

appropriate and in accordance with the guidance provided in Generic Letter 85-06. QA/QC was directly involved with the procurement and modification

review for the ATWS modifications. In addition, they witnessed portions ]

of the acceptance testing and verified that installation was performed in i

accordance with governing instructions.

Training

As noted in inspection report 88-15, the inspector verified that opera-

tions personnel received appropriate training as a result of the ATWS

modifications.

Conclusions

The licensee has implemented, and is continuing to implement, a plan to

comply with 10 CFR 50.62. QA controls governing that implementation have

been adequate. As of this date, there are still three issues that need to

be accomplished. j

'

Replacement of ARI analog transmitter / trip units with one of a

different design to ensure diversity from RPS.

NRC acceptance of RPT single trip coil design.

l

NRC acceptance of ARI and RPS electrical independence.

No violations or deviations were identified.

9. Onsite Followup of Events (93702)

Diesel Generator No. I tripped at 5:56 p.m., on January 12, 1989, causing

a loss of emergency bus E-1. The DG was supplying power to E-1 to support

testing of the normal off-site power circuits on bus ID. Unit I was

defueled and Unit 2 was operating at 100% power. The licensee reported

that all other safety equipment operated as designed.

The licensee had trouble re-energizing E-1. A work clearance had to be

removed to re-energize E-1 from the normal off-site source 10. The unit

auxiliary transformer, the off-site supply in this case, could not be

re-energized immediately because the test position lever in the back of

the 4160 V breaker cabinet was stuck. An undervoltage relay, subject to

modification, had a contact reversed, preventing breaker closure. The

operator also had trouble seating the breaker control power fuses,

_ ____________________ ___

_ _ _ _ _ _ _ _ _ ._ __. . _ _ _ _ . _ _ _ . _ _ _ _ _ . _ ,

- .

.

.

15

contained in a holder, in the fuse holder for two breakers. Additionally,

operators found the master ID breaker closing spring discharged with the

toggle switch for the charging spring motor in the off position,

preventing breaker operation. Operations re-energized ID at 7:20 p.m. and.

E-1 at 10:30 p.m. the same day.  ;

The diesel generator had tripped when the " Auto" light on the local DG

contrcl panel shorted, causing a loss of control power. The licensee

found that two sets of fuses in series with the shorted light were

different than the sizes specified by the applicable drawing. The pair of

fuses nearest the light were 15 amp instead of 10 amp, while the supply

control power had 15 amp fuses instead of 30 amp. One of the latter fuses

blew when the short occurred. The licensee repaired the light, replaced

the fuses, tested the DG, and returned the DG to operable status.

Additionally, the licensee found at least one set of fuses in the DG No. 3

control panel different from the drawings. This was found while the

licensee was re-verifying fuse sizes in the other DG control panels.

An Allen-Bradley relay, Model 700 DC-N200Z1, failed on DG No. 3 during the

month. This relay provides the low starting air pressure alarm for the

DG. DG No. 3 was never inoperable, since the relay only provides

annunciation.

The inspector did not complete reviewing either of the above events. That

review will be completed after the associated LER is issued. The related

inspection will address, at a minimum: fuse control; operator error

related to closing spring motor; breaker maintenance; modification

installation; and repeat relay failures.

No violations or deviations were identified.

10. Onsite Nuclear Saftey Group (92701)

The inspector reviewed the ONS organization, staffing, and work scope with

the Director - ONS and his staff. That review included a brief discussion

of the operating experience feedback program responsibilities of ONS. An

ONS engineer demonstrated the Plant Status Monitor System, an EPRI

(Electric Power Research Institute) personal computer based system. The

PSM model at Brunswick incorporates a Probabilistic Risk Assessment model

with the Technical Specifications for the fire protection system. The PSM

could generate clearances, LC0 information, and revised core damage

frequency numbers. The system will be tested by the Radwaste/ Fire

Protection group.

No violations or deviations were identified.

11. Action on Previous Inspection Findings (92701)

a. (CLOSED) Inspector Followup Item (325/87-20-03 and 324/87-20-03)

Monitor Licensee's Program to Increase Reliability of the Main

Generator Voltage Regulator System. The licensee performed, as a

j

i

-- - _ - - _ - - ------ ___

1

- .

.

.

16

part of their scram reduction program, an evaluation of the 1986 and

1987 trouble tickets and scram reports. From this evaluation, they

determined that five scrams were directly related to the main

generator voltage regulator system's erratic behavior. They l

concluded that the erratic behavior was directly attributed to the

potentiometer design. The subject potentiometer design was suscep-

tible to dirt contamination. This dirt contamination, along with

elevated temperatures, such as those generally observed dur ing normal

plant operations, caused resistance changes within the potentiometers.

The licensee believes that the resistance change is the root cause of

the regulator system's erratic behavior. The licensee, in an effort

to improve the main generator voltage regulator system's reliability,

replaced the existing 70P and 90P potentiometers with sealed potentio-

3 meter units for both Unit 1 and Unit 2. The inspector reviewed the

licensee's direct replacement documentation and verified that the

replacement work was completed under work requests 87-AEBEl, 87-APHE1,

87-AEBD1, and 87-APHBl. The inspector, based on the results of the

licensee's evaluation, concludes that the sealed potentiometer should

contribute to reducing voltage regulator erratic behavior and improve

overall reliability,

b. (CLOSED) Inspector Followup Item 325/88-05-04 and 324/88-05-04,

Hydrogen Leak in Turbine Building Pipe Tunnel. Also inspected in

Report No. 88-14. The inspector reviewed the licensee's Operating

Experience Report 88-024, Unusual Event - Hydrogen Leak, and

evaluated the licensee's root cause assessment. The licensee

attributed the root cause to a weakness in the acceptance test

procedures associated with the modification to the hydrogen gas water

chemistry addition system. The test procedures did not adequately

test the new valve installation assemblies i r. all operational

configurations. The 0-HWCH-V102 valve, during system operation, can

be open or closed. However, this valve was leak tested only in the

open position. In addition, the test procedure did not prohibit the

valve from being backseated prior to testing. With this valve

backseated in the open position during initial leak testing, the

licensee concluded that no packing leakage would have been detected.

The packing seal problem in the V102 valve was not discovered until

after system fill with the valve in the closed position.

The licensee, ir response to this event, initiated specific changes

to the hydrogen water chemistry system plant modification package

PM-86-081. In PM revision 28, dated March 15, 1988, the licensee

revised acceptance test number 52, section 5.3 and 5.4, to require

that the valves installed in the hydrogen piping be leak tested in

all operational conditions with backseating of valves prohibited

during leak testing. In addition, the licensee revised the PM on

March 30, 1988, revision number 37, to require an operational

hydrogen leak check during initial system fill conditions.

The inspector reviewed revision 28 and 37 changes to the PM and has

concluded that these changes should prevent the recurrence of

,

-

-____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

_

-

1, e 6 l

.

.

'

17~

hydrogen leakage associated with any future system modification which

requires a system fill. In addition;. the inspector has determined -

that the licensee has made an adequate assessment of > the root _cause

which attributed to this event and_ has , taken the appropriate-

corrective actions. j

c. (CLOSED) . Inspector Followup Item -325/88-15-04 and 324/88-15-04,

Failures of GE 305 Auxiliary Contact Adder Blocks. The inspector

reviewed EER 88-0221, dated August _2, -1988, which evaluated - the

effects of the CR305 auxiliary contact: failures experienced by the~

licensee. Thefevaluation, which included results of field

inspections of the 305 devices and test results of' a BSEP approveo .j

test conducted by GE, concluded that the old CR305 devices should be

-replaced with the new 305 devices (date code CC or later), but only

on an "as f ailed" basis. This conclusion was based on GE test

results. and field inspections over 6 weeks. The'GE test tested 76

CR305 adder blocks. The test included contact resistant measurements

and exercised the blocks over 45,000 cycles to datermine an expected-

failure rate. One block failure was noted. Field inspections of 133

important safety-related _ breaker compartments conducted on six

different occasions over six weeks revealed no failures. Based on-

the low expected failure rate of the CR305 adder blocks demonstrated-

by testing and the lack of failures found in the field' the licensee-

,

concluded that the CR305 failure rate did not significantly affect

MOV reliability. The licensee will replace _the old CR305 blocks only

upon. failure. The inspector concluded that the license?'s actions

were appropriate.

d. (CLOSED) Unresolved Item 325/87-42-02 and 324/87-43-02, Wrong Unit

Event Involving RHR Pump Breakers. On December 21, 1987, an operator

racked out the 1A RUR pump breaker instead of the 2A RHR pump breaker

as required by the clearance. The inspector reviewed the licensee's

OER-87-087, which determined that the root cause of this event was

directly attributed to the lack of attention to detail of the

-

operators while hanging clearance 2-1489. In addition, the operator

which performed the clearance confirmation check, as required by

AI-58, Equipment Clearnace Procedure, failed to identify that the 1A

RHR pump was racked out in lieu of the 2A pump. Technical Specifica-

tion 6.8.1.a requires the licensee to establish, implement, and

maintain written procedures as recommended by Appendix A of

Regulatory Guide 1.33, November 1972, Item A.3, Equipment Control

i

(locking and tagging). At the time of this event, procedures were in

L place for placing the 2A RHR pump clearance. However, the licensee,

due to a lack of operator attention to detail, failed to properly

implement the procedure. This is identified as a Violation: Lack of

,

Operator Attention to Detail Leads to Inadequate Implementation of a j-

l 2A RHR Pump Clearance (325/89-02-01 and 324/89-02-01).

The inspector did verify that once the operator error was identified,

plant operations took the proper actions to place the inoperable RHR

1A pump under an LCO and restore it to an operable status. The

-

-. __ _ _ _ _ _ _ _ _ _ _ _ _ _ 1

-

w .

.

18

licensee also identified, in their OER, that inappropriate breaker

labeling and the differences in E-3 emergency switchgear compartment i

layout from that of the E-1, E-2, and E-4 switchgear were l

'

contributing factors to this event.

The licensee, in response to this event, conducted real time training

with the operations staff on this event and made improvements to the

identification of emergency switchgear compartments (i. e., improved

equipment labeling and unit color coding). The licensee revised the

plant electrical system operating procedures 1-0P-50 and 2-0P-50 to

require that when a 4160 V emergency bus breaker is racked out, this

condition will also be verified by control room personnel who shall

verify the rack-out using the position indications in control room.

The inspector reviewed the licensee's training records and verified

-

that the operations staff, through course module OR88-1-108, was

instructed on this event. The inspector reviewed the current

revisions to the plant electrical system operating procedures and

verified that control room indication will also be utilized to verify

the position of 4160 V emergency bus breakers when rack-out

operations are being performed. Also, during a routine walkdown of

the emergency switchgear on January 23, 1989, the inspector verified

that the switchgear compartments were properly labeled and color

coded with the exception of the 1A RHR pump switchgear compartment.

The 1A RHR pump switchgear compartment had not been color coded or

labeled as required by PNSC item 88.008.03.b. By the close of the

inspection, the licensee had correctly labeled and color coded the 1A

RHR breaker compartment.

e. (CLOSFD) Unresolved Item 325/88-01-02 and 324/88-01-02, Seismic

Requirements for Radiation Monitoring System. In response to this

concern, the licensee generated PCN 06539A to determine the seismic

requirements for the radiation monitoring system. The licensee found

that the off gas vent pipe (stack) radiation monitor system is

designed to seismic class II requirements. Seismic class II

equipment is seismically mounted, not designed to operate during or

after a seismic event, and its f ailure will not affect seismic

equipment. The inspector determined that if the stack radiation

monitor sample system / pump were to fail, a low flow or the loss of

discharge flow condition would be annunciated on the annunciator

UA-03 window 6-3 in the control room. In addition, upon a loss of

flow condition, a group 6 isolation will occur, which trips and

isolates reactor building ventilation, starts standby gas treatment,

closes inboard and outboard containment purge and vent valves, and

closes the post accident sample system valves to the torus. Since

the pump skid appeared seismic Class II, as required, and the motor

failure would have been detected, no violation is being issued.

Further, the inspector verified that the motor is now correctly

mounted.

One violation was identified.

-

__

ni .

w L a Jo

4 ,

,

.

~

19

l 12. Exit Interview (30703)

The inspection scope and findings were summarized on February 1, ~ 1989,

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

areas inspected ~ and discussed in detail the inspection findings listed

below and in -the report summary. Dissenting comments were ' not received

~

from the licensee. Proprietary information is not contained. in this

report.

Item Number Description / Reference Paragraph

325,324/89-02-01 VIOLATION - Lack of Operator Attention to-Detail

Leads to Inadequate Implementation of a 2A RHR

Pump Clearance, (paragraph 11.d).

325,324/89-02-02 LIV - Inadequate Design of Flow Restricting

Orifice Plates, (paragraph 5).

325/89-02-03 URI - Inadvertent Draining of SLC. Tank,

. (paragraph 4.b).

325,324/89-02-04 URI -' Inadequate Control of Electrical Physical

Separation Provided for Divisionalized Raceway,

-(paragraph 4.c).

325,324/89-02-05 'IFI - Followup on Valve Task Group Findings,

(paragraph 6 b). )

13. Acronyms and Initialisms

A0 Auxiliary Operator-

APRM Average Power Range Monitor

ARI Alternate Rod Injection

ATWS Anticipated Transient Without Scram

BSEP Brunswick Steam Electric Plant

C0 Control Operator

DBE Design Basis Earthquake

DC Direct Current

DG Diesel Generator

D/P Differential Pressure

EER Engineering Evaluation Report j

ERFIS Emergency Response Facility Information System

ESF Engineered Safety Feature

GE General Electric

GPM Gallons Per Minute

HCU Hydraulic Control Unit

HEPA High Efficiency Particulate Air

HP Health Physics

HPCI High Pressure Coolant Injection

I&C Instrumentation and Control

ID Inside Diameter

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

__.

l

-

l

20

I

IE NRC Office of Inspection and Enforcement

IFI Inspector Followup Item

IPBS Integrated Planning Budget System

LCO Limiting Condition for Operation

LER Licensee Event Report

LIV Licensee Identified Violation

MI Maintenance Instruction

MOV Motor Operated Valve

MST Maintenance Surveillance Test

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

OER Operating Experience Report

ONS Onsite Nuclear Safety

OP Operating Procedure

PA Protected Area

PCN Plant Change Notice

PM Plant Modification

PSM Plant Status Monitor

PNSC Plant Nuclear Safety Committee

PT Periodic Test

QA Quality Assurance

QC Quality Control

RCIC Reactor Core Isolation Cooling

RHR Residual Heat Removal

RPS Reactor Protection System

RPT Recirculation Pump Trip

RWCU Reactor Water Cleanup

SBGT Standby Gas Treatment

SCFM Standard Cubic Feet per Minute

SDV Scram Discharge Volume

SER Safety Evaluation Report

SF Shift Foreman

SLC Standby Liquid Control

SRM Source Range Moi.itor

SRO Senior Reactor Operator

STA Shift Technical Advisor

TI Temporary Instruction

TS Technical Specification

URI Unresolved Item

V Volt

WR&A Work Request & Authorization