ML20140B763

Insp Repts 50-413/97-03 & 50-414/97-03 on 970112-0215. Violations Noted.Major Areas Inspected:Licensee Operation, Maint,Engineering & Plant Support

ML20140B763
Person / Time
Site:	Catawba
Issue date:	03/17/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20140B755	List: ML20140B750 ML20140B758 ML20140B763
References
50-413-97-03, 50-413-97-3, 50-414-97-03, 50-414-97-3, NUDOCS 9704010094
Download: ML20140B763 (35)

See also: IR 05000413/1997003

Text

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-413. 50-414

License Nos: NPF-35 NPF-52

Report Nos.: 50-413/97-03, 50-414/97-03

Licensee: Duke Power Company

Facility: Catawba Nuclear Station Units 1 and 2

Location: 422 South Church Street I

Charlotte, NC 28242 l

Dates: January 12 - February 15, 1997

Inspectors: R. J. Freudenberger. Senior Resident Inspector

P. A. Balmain. Resident Inspector

R. L. Franovich, Resident Inspector l

E. H. Girard, Reactor Inspector (Sections E1.3 & E8.8-12)

P. J. Kellogg. Reactor Inspector (Sections E2.2 & E7.2)

R. L. Moore. Reactor Inspector (Sections E2.1 & E7.1)

C. W. Rap). Senior Reactor Inspector (Sections E8.1-7)

J. W. Yorc, Reactor Inspector (Sections E1.1-2)

Approved by: C. A. Casto Chief

Reactor Projects Branch 1

Division of Reactor Projects

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Enclosure 2

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9704010094 970317

PDR

G ADOCK 05000413

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EXECUTIVE SUMMARY

Catawba Nuclear Station. Units 1 & 2

NRC Inspection Report 50-413/97-03. 50-414/97-03

This integrated inspection included aspects of licensee operations,

maintenance, engineering and plant support. The report covers a 6-week

period of resident ins)ection: in addition, it includes the results of

announced inspections ay regional reactor safety inspectors.

Doerations

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Emergency Core Cooling System valve stem leakage flow alarm panels i

provided in the auxiliary building, although not required by the Final l

Safety Analysis Report, were not being maintained as a reliable means of i

locating potential reactor coolant system leakage sources (Section

01.1).

Maintenance

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The time allowed by Technical Specifications for reactor trip breaker

testing was exceeded because procedural changes to incorporate  !

additional tasks were not evaluated to verify that those changes would

not extend the time to perform the test beyond the time allowed (Section

M1.1).

• The inspector identified that material condition and housekeeping in the

Unit 2 Residual Heat Removal / Containment Spray Heat Exchanger Rooms was

poor (Section M2.1).

. A non-cited violation was identified for failure to follow procedures

that resulted in mispositioned nitrogen backup supply valves that i

degraded the function of two steam generator power operated relief

valves (Section M8.1).

Enaineerina

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. A review of station Problem Identification Process (PIP) reports and

associated corrective actions revealed that the licensee's threshold for

problem identification was at an appropriately low level and that the

Nuclear Safety Review Board had a positive impact on the licensee's

corrective action process. For the PIPS reviewed the licensee had not

failed to identify any unreviewed safety questions (Section E1.1).

. A review of modification packages revealed that the licensee properly

screened and performed the safety evaluations for modifications and test

procedure changes and that no unreviewed safety questions existed

(Section E1.2).

. The licensee met the intent of Generic Letter (GL) 89-10 in verifying

the design-basis capabilities of their motor-operated valves (MOVs).

Several weaknesses were identified. Of these, the more important were

the limited data that was used to establish the capabilities of several

groups of MOVs.and the marginal capabilities of several groups of MOVs.

Enclosure 2

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An Inspector Followup Item was identified to track the completion of

licensee initiated corrective actions. Strengths were identified which

included: knowledgeable personnel who recognized and addressed the

l problems identified, strong

state of the art technology. plant and corporate

leadership support,

in addressing application

industry problems,of

and the detailed thrust / torque requirement calculations that were

developed for each valve group. Based on the NP,C staff's review of the  !

Catawba GL 89-10 program and its implementation, and the corrective

actions initiated by the licensee, the NRC is closing its review of the

GL 89-10 program at Catawba. The completion of these licensee actions  ;

will be assessed as part of the NRC staff's monitoring of the licensee's )

long-term MOV program (Section E1.3). j

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Procurement Engineering performance related to identification, upgrade

and validation of safety-related replacement parts was generally good.

A violation was identified for failure to follow procedures for the

storage and control of the spare parts diesel generator (Section E2.1).

. The engineering department was providing aggressive and effective

support to the operations, maintenance, and modification departments:

the number of open items was at an acceptably low level; and the Top

Equipment Problem Resolution Process was a strength (Section E2.2).

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The scope of the procurement self-assessments was adequate to evaluate

performance of the activity under review. Findings were appropriately

documented and tracked for resolution (Section E7.1).

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Engineering was aggressively pursuing identified equipment problems and

self-assessments were effective in identifying areas for improvement in

the engineering department (Section E7.2).

. The monthly flushing program was effective in controlling clam

population in service water piping (Section E8.1).

Plant Stocort

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. The licensee had existing radiation monitoring systems in the new fuel

unloading and storage areas that were capable of alarming should an

accidental criticality occur. A violation for failure to implement

criticality accident emergency procedures and failure to conduct

evacuation drills was identified (Section R2.1).

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Enclosure 2

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! Report Details

Summary of Plant Status

Unit 1 began the period operating at 100% power and operated at that power

level until February 14, when power was decreased to 59% so that a failed

speed sensor (one of two) associated with the IB main feedwater pump turbine

could be replaced. The specd sensor was replaced, and the unit returned to

full power on February 15.

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Unit 2 began the Jeriod operating at 100% power and operated at essentially

full power througlout the inspection period.

! Review of Vodated Final Safety Analysis Reoort (UFSAR) Commitment.s

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While performing inspections discussed in this report, the inspectors reviewed

the applicable portions of the UFSAR that were related to the areas inspected.

The inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures, and/or parameters.

I. Doerations

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l 01 Conduct of Operations 1

01.1 Valve Stem Leakoff Flow Monitorina Indication

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l a. Insoection Scone (71707, 40500)

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l The resident inspector noted that annunciator panels located in the

l auxiliary building, designed to provide flow indication from valve stem

l leakoff lines, had numerous indications of valve stem leakoff. The

inspector questioned the alarm status of these leakoff lines and

referred to pertinent design basis documents to determine the function

of the annunciator panels.

l b. Observations and Findinas

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During a routine tour of the auxiliary building on January 29. the l

resident inspector identified a number of flow alarms associated with i

Emergency Core Cooling System (ECCS) valve stem leakoff flow monitoring.

The inspector questioned operations personnel about the alarms and

determined that the annunciator panel indications were not considered

reliable and, therefore. the alarms were not attended to. The inspector

also noted that annunciator response procedures were not available to

j provide guidance in response to the alarms.

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The licensee generated station Problem Investigation Process (PIP)

report 0-C97-0265 to document the alarm status on these annunciator

panels. According to the PIP. the reliability 3roblems associated with

the flow alarms has been an ongoing 3roblem. T1e 3rocedure for

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identifying Reactor Coolant System (RCS) leakage. )T/1&2/B/4150/01E.

Identifying Reactor Coolant System Leakage, provides guidance for using

Enclosure 2

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these annunciator panels to identify sources of RCS leakage. The

inspector obtained a copy of the procedure, approved July 16,1996, and

reviewed Enclosure 13.3 Valve Stem Leakoffs to the Recycle Holdup Tank.

Although the enclosure lists the ECCS valves that are represented on the

annunciator panels, using this method to identify RCS leakage is not

required and is implemented at the discretion of the Operations Shift

. Supervisor.

The inspector consulted the FSAR in an effort to determine the design

basis of the valve stem leakoff flow indications. Although ECCS valve

stem leakoff collection was briefly discussed, a discussion of flow i

monitoring of the leakoff was not provided in the context of reactor

coolant system leakage detection or auxiliary building radiological

activity limits.

c. Conclusions

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The inspector concluded that the ECCS valve stem leakage flow alarms

that were not being maintained as a means of locating potential reactor I

coolant system leakage sources. Although no safety basis for the flow i

indication could be identified in the FSAR, an evaluation is appropriate i

to determine whether the equipment should be available and maintained in J

good working condition or should be abandoned.

II. Maintenance

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M1 Conduct of Maintenance '

M1.1 Reactor Trio Breaker Surveillance Testina

a. Jnsoection Scooe (61726)

On February 6. the licensee determined that the time allowed for Unit 2

reactor trip breaker (RTB) testing was exceeded, and RTB inoperability

had exceeded the 2-hour limit specified in Technical Specification (TS)

' 3.3.1. Item 18. Action 9. The inspector reviewed station PIP 2-C97-

0341, reviewed associated testing procedures, and discussed the issue

with licensee personnel.

b. Observations and Findinas

The licensee conducted RTB testing concurrent with Solid State

Protection System testing on February 6. According to TS 3.3.1. Item

18. Action 9. one RTB channel may be bypassed (inoperable) for up to two

hours for surveillance testing per TS Surveillance Requirement 4.3.1.1.

provided that the other RTB channel is operable. The work associated

with the surveillance testing was completed within the allowed 2-hour

time )eriod; however, paper work to clear the work order and declare the

RTB clannel operable was not completed until after the allowed time  ;

period had elapsed by 20 minutes. As a result. RTB testing required i

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Enclosure 2 l

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entry into the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> shutdown action of TS 3.3.1. Item 18. Action 9. I

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' The licensee initiated P75 2-C97-0341 to document the issue. The i

inspector reviewed the 'T and discussed the occurrence with licensee i

personnel. The cause of the time delay was attributed to multiple

changes to the test ?rocedure that required the performance of

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additional tasks. T1e licensee did not attemat a walkthrough  !

verification to ensure that these procedure c1anges did not i

significantly impact the time necessary to cc.oplete testing. Corrective

actions proposed in the PIP include procedural changes to enhance the

efficient use of time in conducting the test. l

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c. _ Conclusions  !

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The inspector concluded that exceeding the time allowed by TS for RTB

testing because of outstanding papenvork did not adversely impact plant 1

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safety. However, the procedural changes to incorporate additional tasks

were not evaluated to verify that those changes would not extend the

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time to perform th.e test beyond the time allowed by TS, without entering

a shutdown TS action.

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M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Unit 2 Containment Soray and RHR Heat Exchanger Room Observations

a. Insoection Scooe (62707, 61726, 40500)

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The inspector observed portions of the following surveillance activities l

performed on the 2B containment spray pump:

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PT/2/A/4200/09A, Auxiliary Safeguards Test Cabinet Periodic Test

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-PT/2/A/4200/04C, Containment Spray Pump 2B Performance Test

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PT/2/A/4203/03. Leak Rate Determination for NS System Outside of

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Containment

During the performance of these tests, the inspector observed poor ,

housekeepino and material conditions in the Unit 2 Residual Heat Removal i

(RHR)/ Containment Spray heat exchanger rooms. l

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b. Observations and Findinas

Surveillance Test PT/2/A/4203/03, Leak Rate Determination for NS System

Outside of Containment, is performed within six months of each refueling

outage and consists of a walkdown of containment spray system piping and i

components located outside of the reactor containment while the system

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is pressurized. Components with evidence of leakage are identified for

j repair. During the portion of the walkdown performed in the 2B

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RHR/Contaiu,,ent Spray heat exchanger room the inspector and the licensee

Enclosure 2

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technician observed an uncontained leak spraying from a containment  ;

saray system vent located above the containment spray heat exchanger.

T1e inspector investigated areas in the lower part of the room and

identified that a significant amount of boric acid had accumulated on

safety-related components in this area, including the heat exchanger

hold down bolts and supporting structure. The accumulation of boric

acid indicated that this leakage source had existed previously and would

occur when the system was in operation and pressurized. The inspector

found similar boric acid accumulation in the A train heat exchanger

room.

In contrast to the conditions in the 2B heat exchanger room, a previous

atte.nn D contain leakage was obvious in the A train heat exchanger

room as evidenced by a drip bag installed on the heat exchanger vent

piping. The inspector discussed the licensee's leak containment I

practices for these rooms with radiation protection management. The ,

inspector found that the heat exchanger rooms were classified as  !

nonrecoverable from a radiological contamination standpoint because of

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the chronic leakage sources which make the rooms difficult to maintain

decontaminated. From the dicussions, the inspector discerned that the  ;

licensee did not routinely install drip bags or leak containments in

areas which are considered " nonrecoverable."

The inspector performed additional inspections in these rooms and

identified a substantial amount of debris left in the heat exchanger

, rooms, including discarded scaffold tie down wires, several ropes tied

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to instrument air lines and safety-related valves, sections of unsecured 1

insulation left on valve actuators, damaged flexible electrical conduit,

trash, and discarded rubber gloves.

Following identification of these issues the licensee developed a plan

to repair the leaks and correct housekeeping issues. The licensee

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tightened the 2B heat exchanger pipe cap and the associated vent valves

l which stopped the leak, Vent valves associated with the 2A heat

exchanger were also tightened and no leakage was observed when the pump

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was subsequently operated (PIP 2-C97-0349). Station management

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requested a root cause evaluation be performed by the safety review

group to determine how conditions were allowed to degrade in the heat

exchanger rooms and to assess how ioentified leaks are addressed on all

ECCS components. The licensee oIso performed walkdowns of other

infrequently entered areas and found additional instances of where

material condition or housekeeping were substandard, but not as poor as

l conditions in the Unit 2 RHR/ containment spray heat exchanger rooms.

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c. Conclusions

The ins'ector

> identified that material condition and housekeeping in the

Unit 2 Residual Heat Removal / Containment Spray Heat Exchanger Rooms was

poor. Poor conditions resulted in part because of uncaptured

containment spray system leakage that resulted in accumulation of boric

Enclosure 2

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i technician observed an uncontained leak spraying from a containment '

s) ray system vent located above the containment spray heat exchanger.

Tie inspector investigated areas in the lower part of the room and

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identified that a significant amount of boric acid had accumulated on

safety-related components in this area, including the heat exchanger

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hold down bolts and supporting structure. The accumulation of boric

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acid indicated that this leakage source had existed previously and would

occur when the system was in operation and pressurized. The inspector

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found similar boric acid accumulation in the A train heat exchanger

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room.

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In contrast to the conditions in the 2B heat exchanger room, a previous

attempt to contain leakage was obvious in the A train heat exchanger

room as evidenced by a drip bag installed on the heat exchanger vent

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piping. The inspector discussed the licensee's leak containment

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practices for these rooms with radiation protection management. The

inspector found that the heat exchanger rooms were classified as

nonrecoverable from a radiological contamination standpoint because of

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the chronic leakage sources which make the rooms difficult to maintain

i decontaminated. From the dicussions, the inspector discerned that the

licensee did not routinely install drip bags or leak containments in

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areas which are considered " nonrecoverable."

The inspector performed additional inspections in these rooms and

identified a substantial amount of debris left in the heat exchanger

rocms, including discarded scaffold tie down wires, several ropes tied  ;

to instrument air lines and safety-related valves, sections of unsecured '

insulation left on valve actuators, damaged flexible electrical conduit. '

trash, and discarded rubber gloves. i

Following identification of these issues the licensee developed a plan

to repair the leaks and correct housekeeping issues. The licensee

tightened the 2B heat exchanger pipe cap and the associated vent valves

which stopped the leak. Vent valves associated with the 2A heat

exchanger were also tightened and no leakage was observed when the pump i

' was subsequently operated (PIP 2-C97-0349). Station management l

requested a root cause evaluation be performed by the safety review

group to determine how conditions were allowed to degrade in the heat

exchanger rooms and to assess how identified leaks are addressed on all

ECCS components. The licensee also performed walkdowns of other

infrequently entered areas and found additional instances of where

material condition or housekeeping were substandard, but not as poor as

conditions in the Unit 2 RHR/ containment spray heat exchanger rooms.

c. Conclusions

The inspector identified that material condition and housekeeping in the

Unit 2 Residual Heat Removal / Containment Spray Heat Exchanger Rooms was

poor. Poor conditions resulted in part because of uncaptured

containment spray system leakage that resulted in accumulation of boric

Enclosure 2

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acid on safety-related components in these rooms. The inspector also

identified material condition discrepancies. The licensee's subsequent

inspection of other infrequently accessed areas identified similar l

conditions. These observations indicated that areas which are

considered " nonrecoverable" from a radiological contamination 1

perspective had not received a commensurate level of care as frequently

traveled areas in the plant.

M8 Miscellaneous Maintenance Issues (92902)

M8.1 LClosed) Unresolved item (URI) 50-414/96-20-01: Mispositioned Nitrogen

Backup Supply Valves Result in Degrading the Function of Steam Generator

(SG) Power Operated Relief Valves (PORVs)

During this inspection period the licensee completed investigation of

this valve mispositioning event. The licensee identified that the

nitrogen supply isolation valves were in the closed position for SG PORV  !

2SV-1 in response to a low nitrogen pressure alarm received in the main '

control room when a maintenance technician found the valves closed in

the process of changing nitrogen bottles. Additional licensee

inspections identified that nitrogen supply isolation valves for SG PORV

2SV-13 were also closed. This was the first opportunity to iuentify the I

mispositioned valves.

The licensee determined that four nitrogen supply isolation valves were

left closed for a period of approximately 13 days following surveillance

testing performed on SG PORVs 2"V-1 and 2SV-13 on December 22. 1996.

Two individuals performing the t?st failed to follow a portion of

restoration steps in Surveillance Procedure PT/2/A/4200/31A. SG PORV and

Block valve D/P Stroke Test. Specifically, two restoration steps were

not completed to open the nitrogen supply isolation valves (Steps

12.1.21.5 of Enclosures 13.1 and 13.3 for SG PORVs 2SV-1 and 2SV-13.

respectively). The licensee determined that a contributing cause was

providing one procedure step to perform multiple actions that were in

separate areas of the valve room areas.

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Failing to follow Procedure PT/2/A/4200/31A restoration steps resulted

in disabling the safety-related gas su) plies for SG PORVs 2SV-1 and 2SV-

13 for a period of time in excess of t1e time allowed by TS 3.7.1.6.

Steam Generator Power Operated Relief Valves. With one less than three

required operable SG PORVS the licensee is required to restore the

i inoperable SG PORV to operable status within 7 days or take additional

I actions to shutdown and place RHR inservice. This TS allows one SG PORV

l to remain inoperable indefinitely.

The purpose of the safety-related backup supply as stated in the TS

! Bases is to mitigate the consequences of a steam generator tube rupture

I accident concurrent with a loss of offsite power (i.e. loss of

. instrument air which normally controls the SG PORVS). During this

period, two of the four Unit 2 SG PORVs were fully operable. With the

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l' exception of the nitrogen backup supplies, the remaining two were

functional and could be operated during a steam generator tube rupture

event without complications resulting from a loss of offsite power or

instrument air. For a SG tube rupture event, the PORV on the affected

SG is assumed unavailable. With nitrogen backup supplies isolated on SG <

PORVs 2SV-1 and 2SV-13, one SG PORV would have remained controllable

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from the main control room and SG PORVs 2SV-1 and 2SV-13 could be

locally operated if needed per Emergency Operating Procedure

j EP/2/A/5000/ E-3. Steam Generator Tube Rupture.

Corrective Actions

1~ Upon discovery of the of the isolated nitrogen supplies on SG PORV 2SV-

1. the licensee recognized the significance of the condition and

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promptly checked the remaining three Unit 2 SG PORVs and all four Unit 1

SG PORVS and identified that one additional SG PORV on Unit 2 (2SV-13)

had its nitrogen supply isolated.

1 The licensee 3romptly opened the valves and restored the nitrogen

supplies for )oth SG PORVs. In addition, after identification of the

, two mispositioning events the licensee displayed an appropriate

sensitivity to a possible tampering / sabotage event and performed

j additional verifications of equipment located in the same areas (i.e..

main steam safeties and turbine driven auxiliary feedwater steam supply

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valves). The licensee also secured access to these rooms on both units

until investigation of the possible tampering concluded that the  ;

mispositionings were not deliberate.

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In addition to the immediate corrective actions discussed above. the  !

licensee counseled the two individuals involved in performing the valve

manipulations and initiated revisions to the SG PORV surveillance

procedure to include separate steps and signoffs for each valve

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manipulation. Similar Engineering test procedures will be reviewed for

steps requiring multiple actions separated by time or distance and

, changes will be made as necessary. The licensee submitted LER 50-

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414/97-01 to address this issue on February 3, 1997.

4 The inspector concluded that the licensee's corrective actions were

. appropriate and timely. Failing to follow procedures which resulted in

disabling the safety-related gas supplies for SG PORVs 2SV1 and 2SV13 is

a violation of TS 6.8.1. Procedures and Programs. This violation meets

the criteria of Section VII.B.1 of the Enforcement Policy for exercise

of discretion and will be considered a Non-Cited Violation (NCV 50-

j 414/97-03-03. Mispositioned Nitrogen Backup Supply Valves Result in

r Degrading the Function of SG PORVs).

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M8.2 (Closed) Licensee Event Reoort (LER) 50-414/94-002. Rev. 01: Reactor  !

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Trip Breakers Opened Due to Component Failures

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The LER was revised by the licensee to correct inaccuracies identified

by the inspector during a previous inspection (refer to NRC Ins)ection l

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Report 50-413.414/96-05). The inspector reviewed the revised LER and

verified the inaccuracies were corrected. This item is closed.

III. Enaineerina

El Conduct of Engineering

El.1 Review of Problem Identification Process

a. Insoection Scooe (40500)

The inspectors reviewed a sample of the PIP reports identified by the

licensee during 1996 and the first months of 1997. m order to assess

the licensee's corrective action process and the * ::pect of the Nuclear

Safety Review Board (NSRB) on the process,

b. Observations and Findinas  !

The inspectors reviewed the following PIP reports that were selected

from a list of PIPS written over the past year:

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PIP No. 2-C96-1495. concerninq sheared or missing turbocharger

bolts on Diesel Generator (D/G) 2B.

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PIP No. 2-C96-0475. concerning a leak coming from a cracked socket

weld on a vent line on D/G 2A.

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(The remaining PIPS related to 10 CFR 50.59 safety evaluations.)

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PIP No. 0-C96-0812. involved conflicting information in the 50.59

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evaluation and a flow diagram.  ;

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PIP No. 0-C96-1024. did not contain a 50.59 evaluation or

screening document because of personnel error.

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PIP No. 0-C96-2044 this was a question raised by the NSRB

screening concerning the adequacy of the documented discussion.

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PIP No. 1-C96-2040, did not adequately discuss the decision that

the margin of safety discussed in the TS was not reduced (NSRB

identi fied) .

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PIP No. 0-C96-2046 and PIP No. 1-C96-2049. questions concerning i

adequacy of documented discussion raised by NSRB.

Enclosure 2

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PIP No. 1-C96-2049 and No. 2-C96-2051. questioned by the NSRB l

review. Their review indicated that the 50.59 was directed at the

modification implementation process when the safety analysis

should have been directed at the physical changes to the plant

that the modifications addressed.

None of the resolutions for the PIPS identified a failure to find a

Unresolved Safety Question (US0). j

c. Conclusions

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The inspectors' review of selected PIPS and associated corrective I

actions revealed that the licensee's threshold for problem I

identification was at an appropriately low level and that the NSRB had a

positive impact on the licensee's corrective action process. For the

PIPS reviewed, the licensee had not failed to identify any US0.

E1.2 Review of Safety Evaluations

a. Insoection Scooe (37550)

The inspectors reviewed a sample of the licensee's safety evaluations  !

per 10 CFR 50.59. The evaluations were reviewed with respect to the  ;

threshold for determining if an US0 existed because of an increase in l

the probability of a design basis accident occurring, an increase in '

equipment malfunction, a reduction in the margin of safety, or an i

increase in radiation dose consequences.  !

b. Observations and Findinas

The inspectors reviewed the following 10 CFR 50.59 safety evaluations

for modifications being performed to the Catawba Nuclear Station: j

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50.59 evaluation for modification No. NSM CN-21341, which was used

for the replacement of certain carbon steel sections of the ,

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Nuclear Service Water System (RN) with stainless steel. Almost

complete blockage due to corrosion products had been observed in.

some of the two and four inch diameter lines.

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50.59 evaluation for modification No. NSM CN-11355, which was used

for replacing Containment Penetration Valve Injection Water (NW)

globe valves with gate valves because of hydrogen embrittlement

problems with the stainless steel springs (type 17-7 PH). general

operating difficulty, and problems with position indication.

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50.59 evaluation for modification No. NSM CN-21300, which was used

for refurbishment of the vertically mounted Containment Spray

System (NS) Heat Exchangers 2A and 28. Baffle plates in the heat

exchangers are supported by tie rods / spacers made from carbon

steel and over a period of years corrosion had attacked these

Enclosure 2

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components. The structural integrity was restored by inserting l

rods both above and below the baffle plates and then welding the

rods to the shell.

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50.59 evaluation for changing Test Procedure PT/2/A/4350/128 for

Diesel Generator (D/G) 28. Additional loads were added to the

test for this D/G and the test is used to demonstrate acceptable

response of the governor and voltage regulator to load changes

after maintenance has been performed.

c. Conclusions

The inspectors concluded that the licensee had properly screened and l

performed the safety evaluations for the modifications and test l

procedure change, and that no USQ existed. i

El.3 Generic Letter 89-10 Program Imolementation  ;

l

a. Insoection Scooe (Temporary Instruction 2515/109) 1

1

This inspection provided an assessment of the licensee's implementation

of GL 89-10. " Safety-Related Motor-Operated Valve Testing and

Surveillance". The licensee notified the NRC that they had completed

implementation of GL 89-10 in a letter dated February 20, 1997.

The assessment conducted during this inspection included evaluations of:

the scope of MOVs included, the calculations of the design basis

differential pressure, the determinations of MOV settings and

verifications of MOV capabilities. the periodic verification of MOV

capabilities, and the MOV post maintenance and post modification

testing. The inspectors conducted the assessment through a review of the

licensee's GL 89-10 implementing documentation and through interviews

with licensee personnel. The documents reviewed included: "NRC Generic

Letter 89-10 Program Plan," Rev. 4: " Guideline for Performing Motor

0]erated

"

Valve Reviews and Calculations" DPS-1205.19-00-0002. Rev. 0;

'

Evaluation of Rate-of-Loading Effects". DPC-1205.19-00-0002, Rev. 0;

DPC-1205.19-00-0001 Rev.1. " Evaluation of Stem Factor and Stem C.O.F.

A:sumptions;" and the procedures, calculations, test records, etc. ,

referred to in the following paragraphs. In addition, the inspectors

reviewed summary tabulations of MOV information and calculation results

prepared by the licensee. Prominent among the tabulations was a list of

"available valve factors" (AVFs) for the licensee's GL 89-10 gate and

globe valves. The licensee prepared this list at the inspectors'

request to aid them in assessing the capabilities of the licensee's

MOVs. The inspectors compared the AVFs of the licensee's valves to

valve factor requirements established through industry testing to

determine if the AVFs were conservatively higher. The AVFs were

calculated for each MOV using the formulas given below.

Enclosure 2

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

-

.

. .

.

4

10

4

i

AVF (Close) = (Th * [1 - (LSB + U)]) - PL - SR/ (Disc Area * DBDP)

AVF (0 pen) = (Th * [1 - (LSB + U)]) - PL + SR/ (Disc Area * DBDP)

where.

I

Th - thrust available for limit switch control. thrust at

torque switch trip for torque switch control

. LSB = load sensitive behavior

i U - uncertainty (instrument and other uncertainties combined

by square root sum of squares method)

PL - packing load

} SR = stem rejection load

l DBDP = design-basis differential pressure

i

,

b. Observations and Findinas

Scone of MOVs Included in the Proaram

i

The scope of valves in the licensee *s GL 89-10 program was reviewed

,

previously by the NRC and was determined acceptable during Inspection

i 50-413.414/96-02. In the current inspection the NRC inspectors reviewed

the list of MOVs contained in the licensee's program and verified that

the scope had not changed. The list was maintained as the Catawba

-

Nuclear Station Units 1 and 2 Generic Letter 89-10 MOV List, CNS

1205.19-0081. Rev. D2. The scope included 252 gate valves. 154 globe

'

valves, and 66 butterfly valves for a total of 472 valves. This was one

of the largest scopes of any plant.

Determinations of Settinas and Verifications of Caoabilities for Gate

,

and Globe Valves

The inspectors selected and reviewed calculations, test data, and

-

' evaluations for the following sample of valves in order to assess the

licensee's validation of calculation assumptions and their

determinations of MOV settings and capabilities:

1-NC031B Pressurizer power operated relief valve (PORV) block valve

2-BB010B Steam generator (S/G) D outside containment isolation valve

(CIV)

2-SV026B Steam generator C PORV block valve

1-NV091B Reactor coolant pump seal return CIV

1-NIO95A Safety injection test header to sump CIV

2-CA038A Turbine driven auxiliary feedwater pump to S/G D isolation

valve

Enclosure 2

. ,

.

11

The inspectors' findings were as follows:

MOV Sizino and Switch Settinas

Catawba typically used standard industry equations to determine gate

valve thrust requirements for setting and sizing their gate valves.

Valve factors for use in these equations were based on in-plant dynamic

testing results or results from other industry sources. For some valves

on which in-plant testing was impractical, prototype testing was

performed. For Westinghouse gate valves the licensee used the equation

and valve factor developed by Westinghouse to calculate minimum required

thrust. In a few cases, the licensee used Electric Power Research

Institute (EPRI) Performance Prediction Model (PPM) calculations to

establish thrust requirements.

Most of the licensee's globe valves were manufactured by Kerotest. The

thrust requirements for these valves were either calculated using the

vendor's method, with an amount added to account for nonconservatism

found by a licensee test program: or the standard industry equation was

used. For the licensee's other globe valves thrust requirements were

calculated using the standard industry equation.

Thrust Reauirements for Grouos

The licensee grouped similar MOVs and established thrust setting

requirements for each group. From their reviews, the inspectors found

that the thrust setting requirements determined for each valve group and

the current setups of the MOVs were adequate for design-basis

capability. However, they noted weaknesses for several groups. These

weaknesses and the actions which the licensee initiated to address each

are described below:

. Group AD-02 consisted of six 6-inch 900# Anchor / Darling double

disc gate valves. These MOVs had both a close and open safety

function. The thrust reauirements were deter'ained using EPRI PPM

'

'

Anchor / Darling double disc hand calculations. The inspectors

found that the licensee's closing calculations were only for flow

isolation and expressed concern that excessive leakage through the

valves might occur without full seating. To address this concern,

the licensee established an action item in PIP 0-C97-0421 to

respond to the conditions specified in the NRC Safety Evaluation

of the " Electric Power Research Institute Topical Report TR-

,

103237. EPRI Motor-Operated Valve Performance Prediction Program"

(including consideration of leakage requirements).

. Group AD-04 consisted of six 3-inch 1500# Anchor / Darling double

disc gate valves. Catawba evaluated November 1994 instrumented

" prototype" testing and EPRI PPM Anchor / Darling double disc gate

valve hand calculation results to establish the thrust

requirements for these MOVs. The NRC inspectors reviewed the

Enclosure 2

,

.

12

i

results and expressed concern that the licensee's evaluations

showed that the capabilities of two valves in this group had only

marginal capabilities (INC31 and 2NC33). The licensee established

an action item in PIP 0-C97-0421 to provide future modifications

to upgrade the margins for these valves.

1

.

Group BW-01 consisted of eight 3-inch Borg Warner 150# gate

valves. -From dynamic testing, the licensee determined a valve

factor of 1.3 for this valve group. This valve factor was used to

calculate thrust setting requirements for the group. The i

inspectors questioned the reliability of this unexpectedly high l

value, as it was supported only by a single test. The inspectors '

verified that the licensee had reviewed the MOV settings for the ,

remainder of this group to ensure each could support a valve l

factor as high as 1.3. The inspectors found that the licensee

already had plans to dynamic test three other valves from this

group in the upcoming Spring 1997 outage to further assess the

valve factor. The licensee established an action item in PIP 0-

C97-0421 specifying the additional dynamic testing of these three

valves. ,

. Group WL-01 consisted of two 6-inch Walworth 150# gate valves.

The minimum thrust requirements for these MOVs was based on a .

valve factor of 0.40 and they had open safety functions. The  !

calculated open available valve factor for these MOVs was only a

'

little higher, at 0.42. The inspectors considered these MOVs to

be marginal with respect to thrust capabilities. They reviewed

the diagnostic traces for these MOVs to ensure they were lightly

seated such that minimal unwedging force was required to open

them. Further, they verified that industry data showed a valve

factor of 0.40 for these MOVs. The licensee established an action

item in PIP 0-C97-0421 specifying that these MOVs would be

-

modified to increase their thrust margins in the 1997 Spring

outage.

'

. The thrust requirements for the following gate valve groups were

determined using valve factors obtained from the results of a

single dynamic test each: BW-11 BW-13 PC-01. WH-01, and WH-02.

The inspectors found that such limited data provided weak support

for the requirements. The inspectors verified that the valves had

reasonably high available valve factors compared to general

industry results and did not identify any current operability

concerns. The licensee established an action item in PIP 0-C97-

0421 to put in place a plan to document this shortcoming and

monitor and evaluate the future performance of these valves.

• The thrust requirements determined for the following globe valve

groups were considered weak as they were supported by limited

dynamic test data: BW-13. BW-14. and BW-15. Based on a review of

the settings for these valves, the inspectors were satisfied that

Enclosure 2

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

. s

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13

these groups had adequate thrust margins to assure operability.

The licensee established an action item in PIP 0-C97-0421 to

strengthen the validation data for these groups.

The actions which the licensee initiated to address the above weaknesses

were considered satisfactory.

Load Sensitive Behavior

l

The licensee used measured load sensitive behavior values for valves

that were dynamically tested and generally assumed a value of 30% for

set-up of valves that were not dynamically tested. The licensee's

evaluation of the load sensitive behavior data in their dynamic tests I

was documented in calculation DPC-1205.19-00-0002. " Evaluation of Rate-

of-Loading Effects." The licensee was in the process of revising this

evaluation and the inspectors reviewed both revisions. The inspectors

found that the 30% value which the licensee had used in setting up

valves that were not dynamically tested exceeded the mean plus two

standard deviations determined by both the original and new evaluations.

The latest values were used to calculate the available valve factors l

that the inspectors had requested for use in evaluating Catawba's MOVs.  !

The inspectors considered the licensee's assessment and application of i

load sensitive hehavior to be satisfactory.

l

Stem Friction Coefficient l

Catawba's calculations assumed a stem friction coefficient value of 0.15

in determining actuator output capability. This value was obtained from

an evaluation of in-plant test data from several licensee facilities.

However, based on a more recent evaluation of dynamic test data. Catawba

determined that a value of 0.20 should be used for opening dynamic

conditions. They continued to consider a 0.15 value acceptable for

closing. The licensee verified that closing static stem friction

l coefficients did not exceed 0.15 and relied on the assumed rate of

,

loading to account for increased friction under dynamic conditions. The

i

'

licensee's PIP 0-C95-0879 provided an evaluation of the opening ,

capabilities of the licensee's actuators using an opening stem friction

coefficient of 0.20. The PIP documented that the current MOV

capabilities were acceptable. The inspectors reviewed the licensee's

evaluation and concluded that the licensee had adequately determined and

accounted for stem coefficient in verifying the capabilities of their

MOVs.

Diaonostic Eauioment Uncertainties

NRC Inspection 50-413.414/96-02 determined that the licensee was not

'

accounting for VOTES diagnostic equipment uncertainties in the open

direction when measurements were outside the sensor calibration range.

These errors can become very large if the measurements are significantly

outside the calibration range. This issue was addressed by the licensee

Enclosure 2

l

1

%

.

1

14

through PIPS 0-G95-0295 and 0-C95-0879. The inspectors verified that

the PIPS assured that the uncertainties were appropriately accounted for

through evaluations of the existing completed testing and that the

licensee's procedures were revised for future testing.

Desian-Basis Capability

From reviews of examples of the dynamic test evaluations and associated l

test reports, the inspectors generally found that the licensee's testing I

had been satisfactorily used in establishing the design-basis capability

of their MOVs. Catawba's dynamic tests were accurate and well i

cocumented. From the test results. the licensee calculated valve  !

factors for each test. The valve factors for each group of valves were i

displayed graphically with separate lines plotted for flow isolation and I

hard seat values. In general, the valve factor which the licensee

applied to a group of non-tested valves was selected by bounding the

highest valve factor on the graph and then adding 0.01 to that value.

If a test group showed one test to have an abnormally high or low valve l

factor, an engineering evaluation was performed and that valve factor

was removed from the group if appropriate.

l

The inspectors noted two weaknesses in methods which the licensee used i

to determine the group valve factors:  !

. The inspectors identified one instance in which the licensee used

multiple test data points from a single valve in graphically

analyzing the valve factors for a group of valves. This could

have biased the selection of an appropriate group valve factor.

For the instance in question (valve group BW-05), the inspectors

independently analyzed the licensee's data and found that the

valve factor which the licensee applied to the group was

satisfactory.

. The inspectors noted that the licensee's selection of a grou)

valve factor by adding 0.01 to the highest valve factor on t1e

'

graph for a group might not adequately account for variations in

valve factor performance if the valve factor data had a large

amount of scatter. The inspectors statistically assessed licensee

data and identified an example (valve group BW-03) where the valve

factor selected by the licensee was slightly lower than the mean

plus two standard deviations. In this instance Catawba had

selected an open and close valve factor of 0.60 for the MOVs.

Using the mean plus 2 standard deviations of the data available

for this group the inspectors calculated an caening valve factor

of 0.65 and a closing valve factor of 0.64. iowever, the higher

values calculated by the inspectors were not an operability

problem, as the inspectors found that the minimum available valve

factor for these MOVs was 0.69. The licensee stated that they

would review those calculations where the valve factor data had a

large amount of scatter to ensure that an appropriate valve factor

had been selected for the group.

Enclosure 2

l

I

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s

.

15

Jeterminations of Settinas and Verifications of Caoabilities for

3utterfly Valves

The licensee documented their setting determinations and justifications

for the capabilities of the Catawba butterfly valves in calculations.

Additionally, they documented summary information on each butterfly

valve in a spreadsheet which included information on the valves,

0)erators. method of justifying capability (e. g., test program), and

t1e calculated setting margin above that required. From a review of the

spreadsheet, discussions with licensee personnel, and reviews of

exam)les of the calculations, the inspectors found that the settings and

capa)ilities of the licensee's butterfly valves were demonstrated to be

satisfactory.

Periodic Verification

The licensee implemented MOV periodic verification from a valve list and

test status tabulated in a database. The inspectors reviewed the

tabulation and found that it recorded the date of the last test

performed on each valve and specified the date of the next retest. The

verifications were specified at intervals not exceeding 5 years or 3

refueling outages for the licensee's more risk significant group 1

valves. Periods not exceeding 8 years or 6 refueling outages were

specified for the less risk significant group 2 valves. The inspectors

were informed that it was the responsibility of the system engineers to

-

prepare work orders (W0s) to implement the testing. The inspectors

selected three valves (2NC031B, 2RN846A, and 2NIO88B) and verified that

W0s had been arepared requiring them to be static diagnostic tested in

the upcoming Jnit 2 outage (March 1997).

The licensee's periodic verification actions were considered adequate

for closure of GL 89-10. The NRC may re-assess the licensee's long-term

periodic verification program as part of its review of GL 96-05.

" Periodic Verification of Design-Basis Capability of Safety-Related

Motor-Operated Valves", dated September 18, 1996.

'

Post Maintenance and Post Modification Testina

The licensee's Post Maintenance Retest Manual (November 18. 1996

revision), listed the )ost maintenance testing to be performed on

)

licensee equipnent suc1 as MOVs. For maintenance activities potentially -

affecting valve performance, such as packing adjustments, static

diagnostic tests were specified. However, the Manual permitted the

scope of such testing to be reduced where justified by engineering.

Licensee personnel indicated that post modification test requirements

were determined by engineers using the testing specified by the retest

manual as guidance.

To assess the adequacy of the post modification testing implemented by )

the licensee, the inspectors selected and reviewed the testing specified  ;

I

Enclosure 2

. .

.

16

on the controlling documents for the following maintenance and

modification work: WO 95030544 (packing leak). WO 95057402 (packing

leak). WO 96049626 (packing leak and actuator removal). WO 94055288

(operator oil leak). Modification CN-11347 (replace main steam PORV

block valves). Minor Modification CNCE-7446 (gearbox and spring pack

changes), and Minor Modification CE-4715 (actuator replacement). The

inspectors found that the licensee had specified appropriate testing for

these maintenance and modification activities. For example, a full

static diagnostic test was required following packing adjustments.

Aoolicability of McGuire Insoection Findinas to Catawba

The inspectors questioned whether corporate program changes resulting

from the NRC inspection of the licensee's McGuire facility would be

reviewed for applicability to Catawba. The licensee identified an

action item in PIP 0-C97-0421 to address the corporate program changes.

Strenaths

The inspectors observed a number of strengths in the licensee's

implementation of GL 89-10. Particular examples included:

. Highly knowledgeable personnel who recognized and addressed the

problems identified by the Catawba testing and evaluations.

. Detailed thrust / torque requirement calculations that were

developed for each valve group.

. The strong plant and corporate support that was necessarily

provided to complete a program encompassing the number of MOVs

present at Catawba.

. The application of special test programs and state of the art

technology.

'

. Leadership in addressing industry problems such as increases in

actuator ratings.

c. Conclusions

The NRC inspectors concluded that the licensee had met the intent of GL 89-10 in verifying the design basis ca) abilities of their MOVs.

However, the inspectors identified wea(nesses in certain hardware

capabilities and in some data used in the verifications. The licensee

planned actions to resolve the more significant of these weaknesses

which were documented for comaletion in PIP 0-C97-0421. The PIP

specified that the NRC would ]e notified of the completion status of the

planned actions by December 31. 1997. The inspectors identified the

completion of these actions as Inspector Followup Item 50-413.414/97-03-

04. Actions to Address Weaknesses in GL 89-10 Implementation. In

addition, the inspectors also observed a number of licensee strengths.

Enclosure 2

-. - -_

l

. ,

'

l

i 7

1

Based on the NRC's review of th' Catawba GL 89-10 program and its  !

implementation, and the actiors established by the licensee in PIP 0- i

C97-0421. the NRC is closing it!, review of the GL 89-10 3rogram at i

Catawba. The completion of tha actions identified in t7e PIP will be l

assessed as part of the NRC staff's monitoring of the licensee's long-

term MOV program.

E2 Engineering Support of Facilities and Equipment  !

l

E2.1 Procurement Enaineerina

a. Insoection Scone (37550)

The inspector reviewed Procurement Engineering activity related to the

purchase and receipt of safety-related replacement parts. The areas

reviewed included commercial grade dedication (CGD). acceptable

substitutes. receipt inspection acceptance criteria and verification.

resolution of receipt inspection deficiencies, material Quality

Assurance (0A) quality level changes, and salvage / repair of equipment.

T;n. impection included a sample review of licensee 3erformance in these

areas to oetermine if activities were consistent wit 1 applicable ,

regulatory requirements and licensee procedures. Applicable regulatory '

requirements included 10 CFR 50 Appendix B. FSAR, and the following:

ANSI N45.2.13-1976. 0A Requirements for Control of Items and

Services for Nuclear Power Plants

,

RG 1.123. 0A Requirements for Control of Procurement of Items and

Services for Nuclear Power Plant

GL 91-05. Licensee Conniiercial Grade Pro:urement and Dedications

Programs

b. Observations and Findinas

i

'

Technical evaluations for CGD and acceptable substitutes appropriately

identified and addressed replacement parts' critical characteristics.

Acceptance criteria for critical characteristics were adequately )

addressed and verified at receipt inspection. Receipt inspectors ,

demonstrated a strict adherence to the established acceptance criteria  !

and deficiencies were appropriately documented and resolved. Required

post-installation testing identified in acceptance criteria was

appropriately designated on the item and tracked. Replacement parts * QA  !

classification changes were adequately justified. Procurement ,

Engineering evaluations were technically sound and well documented. The l

interface between the corporate and station procurement engineering l

organizations was good I

The inspector reviewed i.he storage and control of replacement aarts from

the Spare Parts Diesel Generator (SPDG). This diesel was purclased as

Enclosure 2

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

4

.

j

.

,

-

j 18

,

i

nuclear safety-related equipment from the Carolina Power and Light  ;

i Company nuclear program in 1987 The nameplate and purchase i

n documentation indicated that this was the same make, model, and original ,

! equipment manufacturer as the installed Catawba Emergency Diesel  !

j Generators (EDGs). The item was designated for QA level.C storage. The l

SPDG receiving document, dated August 28, 1987 for requisition 7330- {

873044, stated that all parts were to be placed on OA hold and that an i

- acceptability evaluation or test would be made prior to use. The i

evaluation was to include a check to assure the physical. chemical and

.

Non Destructive Examination (NDE) test requirements contained in the

! Duke Power Electrical Diesel Generator Specification CNS 1301.00-00-

j 0002. dated May 15, 1984, were met. i

,

4-

i

A walkdown of the SPDG storage building on February 4.1997, identified

deficiencies related to the implemented storage requirements and

! conditions. The storage building was not a OA level C storage area and

! was not a designated hold area under QA organization control. The

i. building was controlled by the maintenance organization. The building i

,

{ was cluttered with other equipment and there was no apparent cleanliness

i standards implemented. Parts were located on decking and railings. I

4

There was no identification on the SPDG, parts, or vicinity that  !

designated the equipment or parts as OA hold. i

t i

!

'

A review of issued replacement parts identified deficiencies related to  !

the control of material and parts from the SPDG. The walkdown noted

i

that numerous parts were missing from the SPDG. These included the

,

turbocharger, ten cylinder \ piston casing assemblies (power packs), shaft

! driven oil and cooling water pumps, and various piping and valves. ,

i There was no documentation available to demonstrate that the required i

j evaluations against the applicable Duke Power specification were

i

'

performed and no documentation of final 0A disposition of these parts. i

A receipt inspection report salvage evaluation dated February 21, 1996,

i

' CN 38501. issued a fuel rack linkage spring from the SPDG as a

i

replacement part for an installed EDG. This was the only 0A final

disposition document located and it did not clearly specify the

l , acceptance criteria used nor reference the Duke Power EDG specification. l

The inspector reviewed the licensee's procurement program and noted that

i there were approved procedures for storage and control of OA condition

i equipment which spaaned the ten year period that the SPDG has been on =

i site. These included QAG-1, Receipt Inspection, and Control of OA l

l Condition Materials. Parts, and Components. Except Nuclear Fuel dated

June 5,1991: NPP-311. Receipt. Inspection, and Testing of 0A Condition <

i Commodities, dated March 7. 1996: and NPP-315 Certification of Items

l from Non-0A to 0A Condition and Re-certification of Salvageable Items.

, dated July, 22, 1996. These procedures required that designated QA hold

-

items were to be stored in a OA controlled hold area and a final 0A

disposition performed prior to release. The storage and material

i control deficiencies discussed in this section are identified as

j Violation 50-413.414/97-03-01. Failure to Follow Procedure for Receipt,

Enclosure 2

! 1

1

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. - -_ -

.

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19

Inspection, and Control of 0A Condition Materials, Parts, and

Components. During the inspection, the licensee documented this issue

on PIP 0-C97-0322 and initiated actions to establish OA level C

cleanliness requirements for the SPDG storage building.

The inspector reviewed the EDG maintenance activities ard EDG

maintenance history to determine if adequate barriers and performance

information were.available to address potential EDG operability concerns.

related to this issue. The power packs had been refurbished and

recycled in the installed EDGs over several years with no failures.

Periodic testing of the EDGs would have identified degraded performance

due to deficient components. Current maintenance procedures require

Quality Control (OC) verification of QA acceptance tags on all safety-

related replacement parts. Maintenance history did not indicate

equipment performance problems due to installation of degraded

components of the type removed from the SPDG, Maintenance barriers and

performance history indicated that the EDG operability had not been

degraded by the installation of SPDG replacement parts.

c. Conclusion

Procurement Engineering performance related to identification, upgrade

and validation of safety-related replacement parts was generally good.

Engineering evaluations were technically sound and well documented.

Violation 50-413,414/97-03-01 was identified for failure to follow

procedures for the storage and control of SPDG replacement parts.

Maintenance practices and EDG performance history indicated that the

material control deficiencies did not degrade the operability of the

installed EDGs.  ;

E2.2 Enaineerina Backloas

-

a. Insoection Scooe (37550) I

Engineering was actively pursuing backlogs in PIPS, Maintenance Work

'

Orders Temporary Station Modifications, and Operator Work-Arounds. The i

inspector reviewed engineering's efforts in these areas.

b. Observations and Findinas

1

The engineering department was active in the identification and

reduction of backlogs in their own work areas, as well as those items

affecting efficient operation of the facility. These items included

operator work-arounds, captured in the Top Plant Work-Around Problem

Resolution (WAPR), and Major Equipment Problem Resolution (MEPR) items.

The inspectors reviewed the outsta.nding lists of these items.

The inspectors reviewed the licensee's Top Equipment Problem Resolution

(TEPR) process. This process provided for the identification and

management focus on important and long-standing plant equipment

Enclosure 2

. . .. . _ . .

,

4

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20

problems. The TEPR process includes MEPR and WAPR listings of

long-standing repetitive or significant equipment problems and operator

work-arounds. Discussions were held with members of the maintenance,

modifications and operations staffs to determine the adequacy of

] engineering support to those organizations. ,

!

.

c. Conclusions

The inspector concluded that the engineering department was providing l

aggressive and effective support to the operations, maintenance and  ;

J

modification departments and were keeping the number of open items at an I

acceptably low level. The TEPR process was identified as a strength by '

the inspector.  ;

,

'  !

E7 Quality Assurance in Engineering Activities

.

l

,

E7.1 Procurement Enaineerina '

a. Insoection Stone (37550. 40500)

. The inspector reviewed the licensee's self-assessment activities j

'

associated with procurement engineering processes. Applicable

4

regulatory guidance was provided by 10 CFR 50. Appendix B. The

following Procurement Engineering self-assessments were reviewed

-

CTS 08-96. Catawba OA Receiving Assessment 4

• -

CTS 07-96. NPP-212-Acceptable Substitutes Procedure

j

-

CTS 06-96 Catawba OA Services Assessment

i -

SA 96-06. Catawba Commodities and Facilities Work Control

j - SA 96-02(GO), Consolidated Performance Audit

,

b. Observations. Findinas. and Conclusion

The scope of the self-assessments was adequate to evaluate performance

of the procurement activity under review. Findings were appropriately

documented and tracked for resolution.

. E7.2 Quality Assurance and Self-Assessments

a. Inspection Scooe (37550. 40500)

The inspectors reviewed completed self-assessments in the engineering

department and corrective actions asr ' ted with those assessments.

Enclosure 2

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

)

• *

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21

} b. Observations and Findinas i

l The inspectors reviewed selected engineering department self-assessments

and corrective actions. These included: ,

-

MOD-01-96, Quality of limited drawings to assure accuracy and

quality

.

-

MOD-02-96, Corrective Minor Modification Process

l

-

M00-10-96, Flow Diagram Assessment I

-

MOD-04-96, Assess all aspects of at least two modifications

i

'

-

MOD-08-96, Review modifications in progress and interim as-built I

drawings

-

CER-03-96. Review three calculations for lead shielding

-

CER-07-96 I&C staff understanding of ICS-A-20. Instrumentation

". Installation Standards

,

l

-

CER-08-96. Quality of engineering calculations

i

3

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CER-12-96, Assessment of snubber program

1

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CER-14-96, Vital battery modification assessment

-

MSE-03-96, Self-assessment of IST program

i -

MSE-04-96, Self-assessment of safety-related heat exchangers

-

MSE-05-96. Technical support program execution

l c. Conclusions

'

The inspectors concluded that the engineering department was performing

effective self-assessments. The assessments were performed by

knowledgeable individuals and were, for the most part.of the proper

! depth. Corrective actions planned for assessment findings were

l comprehensive and of adequate scope.

4

i

l Enclosure 2

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e- -w. -

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l l

E8 Miscellaneous Engineering Issues (92903)

E8.1 Review of Licensee Actions to Imorove Service Water Quality

l

l a. Inspection Scone

The cover letter for Inspection Report 94-17 required the licensee to

- describe actions planned or taken to address poor service water quality

l and the clam population. While this issue did not require inspector

l followup, the inspector did review the licensees actions to date to

improve service water quality.

,

b. Observations and Findinas

1

! The licensee had established a testing 3rogram to' determine the most

l effective means of addressing these pro)lems. Based on this testing,

the licensee had determined that dispersant addition into the service

water pump suction pit would reduce service water piping corrosion due

,

to silt deposition. The licensee )lanned to implement a full-scale test

'

ir the near future. The licensee lad also determined that a flocculent-

addition was more effective at reducing silt deposition than the

dispersant. The licensee was in the process of getting state

l environmental approval to use the flocculent. The licensee planned to

use the flocculent once state approval was obtained.

I In July 1996, the licensee informed the NRC that injection of a biocide

! resulted in unacceptable corrosion rates for service water piping. The

l licensee had concluded that an active biocide program would not provide

l

an additional benefit than already provided by the flushing program:

therefore, biocide injection would not be pursued. The licensee was

continuing a program of monthly flushes on portions of the service water

f

'

system susceptible to clam infestation. The service water (RN) to

-

component cooling and the service water to auxiliary feedwater (CA)

piping flush procedures directed that a representative sample be

collected during these routine flushes to determine the clam population

'

in the service water system. Additionally. Procedure PT/1(2)/A/4200/59.

RN to CA Piping Flush, retype 13. directed additional flushing

depending on the number of clams found in the sample. The inspector

reviewed the data taken for both component cooling and auxiliary

feedwater flushings from December 1992 to December 1996. Except for the

summer months (June through September), the clam count in the sample was t

consistently five or less.

'

During June through September, the maximum

clam count was 28. The inspector noted these values were consistent on i

an annual basis.

c. Conclusions

The inspector concluded that the monthly flushing program was effective

in controlling clam population in service water piping. The

I

effectiveness of the dispersant could not be assessed.

l

Enclosure 2

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3

E8.2 (Closed) Insoector Followuo item (IFI) 50-413.414/94-17-01: Analysis of

Skewed SNSWP Discharge Flow

Paragraph 4 a. of NRC Inspection Report 50-413.414/94-17 stated that

certain plant configurations could allow the heated service water

4

discharge to the Standby Nuclear Service Water Pond (SNSWP) to reenter

the service water intake before any significant cooling had occurred.

.

This "short cycling" would reduce the heat removal capability of the

i service water system. The licensee submitted a new analysis of the

SNSWP which addressed the skewed discharge flow. The NRC accepted the

licensee's new analysis and issued an SER on November 19, 1996.

Accordingly, this IFI is closed.

E8.3 (Closed) Violation (VIO) 50-413.414/94-17-02: Failure to Properly

Translate Regulatory Requirements into Specifications, Drawings, and

Procedures

Example one of this violation detailed findings that the instrument

, inaccuracies for SNSWP temperature and level were not included,

'

resulting in the SNSWP exceeding the maximum allowable temperature of

100 F. The licensee had replaced the temperature sensor and performed

loop accuracy Calculation CNC-1210.04-00-0067. Loop Accuracy Calculation

. for the Standby RN Pond Temperature. Based on that calculation, the

licensee determined that loop uncertainty was 1.03 F for the control

i'

room indicator and was 1.04 F for the Operator Aid Com] uter (OAC).

These values represented a substantial reduction from tie previous 1

uncertainties of 3.4 F and 2.13 F, respectively stated in Inspection

-

Report 94-17.

i

The licensee also performed Calculation CNC-1210.04-00-0069 Loop

Accuracy Calculation for Standby Nuclear Service Water Pond Level - Loop

RN7350. The loop uncertainty for SNSWP level was determined to be 0.43

3 ft for the control room indicator and 0.34 ft for both the alarm and

the OAC. These values represented an increased uncertainty from the

l previous values of 0.202 ft and 0.157 ft, respectively. The licensee

2

' '

attributed this increased uncertainty to rescaling of the level sensor

when SNSWP level was raised by an additional three feet. Although the

f SNSWP level uncertainties increased, the inspector concluded that the

additional three feet compensated for this increase.

.

l Based on the uncertainty reduction for the SNSWP tem)erature instrument

'

loop and the additional three feet of SNSWP level, t1e inspector

concluded that the inclusion of instrument uncertainties would not ,

result in exceeding the SNSWP maximum temperature limit. j

The inspector reviewed both calculations and found that the licensee had

used vendor-supplied data where provided. Since sensor drift data was

'

not provided for the temperature or level sensors, the licensee had

assumed that sensor drift was equal to sensor calibration accuracy

according to EDM-102. Instrument Setpoint/ Uncertainty Calculations.

Enclosure 2

I

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O

6

24

revision 1. However EDM-102 stated that this assumption was valid only

for electronic modules and indicators. EDM-102 stated that sensor drift

for )rocess sensors should not be assumed to be ecual to the sensor

cali) ration accuracy unless supported by publishec or actual data. The

licensee reviewed data published in NUREG/CR-5560, Aging of Nuclear

Plant Resistance Temperature Detectors, and found that sensor drift for

the type of temperature sensor used was greater than that assumed. The

total loop uncertainty calculated using the revised value for sensor

drift was 1.06 F for the control room indicator and the OAC. Since the

licensee was using a conservative value of 1.1 F. the higher

temperature sensor drift value had a small effect. The inspector also

found the same assumption was used for Calculation CNC-1210.04-00-0069.

The licensee provided field calibration results for the SNSWP level

transmitter from May 1988 to January 1996. Using the field calibration

data, the inspector calculated that sensor drift was about 2.0% of

calibrated span. Calculation CNC-1210.04-00-0069 assumed that sensor

drift was 0.51% of calibrated saan. The inspector recalculated the

total loop uncertainties using tie 2.0% of calibrated span value and

found that the overall effect was small. The inspector also noted that

the level transmitter had been replaced in January 1996. Since the

SNSWP level loop calibration frequency was 18 months, no recent data was

available to determine the sensor drift for the new transmitter.

Discussions with the licensee's engineers indicated some confusion about

the intent of the allowance of using sensor calibration accuracy as

sensor drift. EDM-102 stated that sensor drift should not be assumed

equal to device reference accuracy unless supported by published or

historical data. While this statement appeared to discourage equating

sensor drift to device reference accuracy, it does not expressly forbid

making such an assumption. Also. EDM-102 defined five instrumentation

categories to aid in the determination of the type of uncertainty

analysis required. Since the licensee had recently initiated efforts to

apply the EDM-102 instrumentation categories plant-wide, the licensee

had not determined which instrumentation category the SNSWP temperature

and level instrument loops would fall into. The inspector considered

'

this determination important due to the potential impact on instrument

loop calibration 3rocedures and SNSWP operability determinations.

Failure to use pu)lished or actual data to determine sensor drift as

indicated by EDM-102 could result in nonconservative calibration

acceptance criteria. As stated previously, the licensee had initiated a

programmatic review to apply the EDM-102 instrument categories to all

plant instrumentation.

E8.4 (Closed) InsDector Followuo Item 50-413.414/94-17-03: Short Discharge

Leg Flow Verification

Paragraph 4 c. of Inspection Report 94-17 stated that silt accumulation

, near the long service water discharge aath indicated that the service

water discharge flow to the long and s1 ort service water discharge paths

was not evenly split contrary to the engineering analysis. The licensee

Enclosure 2

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conducted short discharge leg flow verification as part of the SNSWP '

. reanalysis. The NRC accepted the licensee's reanalysis and issued a SER

on November 19. 1996. I

E8.5 (Closed) Insoector Followuo Item 50-413.414/94-17-10: Flush Program  !

,

Improvements

As documented in Inspection Report 96-10 and 96-16. the licensee had

, radiographed both trains of service water supply to auxiliary feedwater

piping foe Units 1 and 2. However, the licensee did not document the

i

as-found condition for the 'A' train lines and could not produce the

radiographs. The licensee took additional radiographs of this piping

l near valve RN-250A for both Units 1 and 2 on December 30. 1996, and

October 28. 1996. respectively. The inspector reviewed the radiographs

j and concluded the piping was not fouled.

E8.6 (Closed) Insoector Followuo Item 50-413.414/94-17-14: Quantifying Flow

l Measurement Error

.

J Paragraph 7.e.(3) of Inspection Report 94-17 stated that service water

i flow measurements were potentially affected due to fouling and

! corrosion. The inspector reviewed data obtained during heat exchancer

performance testing and service water pump in-service testing for

1

indications of flow measurement inaccuracies. The containment spray

'

, heat exchangers had an orifice type flow element that provided both

control room and local flow indication. The inspector reviewed

Jerformance data from March 1993 to present for the 1B containment spray

leat exchanger. Analysis of the data found that nearly identical

j temperature differences could be correlated to about the same flowrate

over the entire 3eriod. This indicated there had been no substantial

'

j degradation in t1e flow sensing element over the period reviewed.

Annubars were used to measure service water pump flow during in-service

testing. The inspector reviewed the service water pump in-service test

data from April 1995 through December 1996. The licensee also provided

i

' a trend of in-service test flow data for service water pumps 1B and 2A

,

obtained from September 1994 through November 1996. The trend data was

i consistent with a slight flow increase noted after all four annubars

j were cleaned in late 1996. This indicated that the flow measured by the

annubars was insignificant 1y affected by fouling. The inspector also

,

reviewed the in-service data and found that the measured flow only 1

! differed about 0.5% between in-service test periods. Based on che

! inspectors review of this data, the inspector concluded that any annubar

fouling was not adversely effecting flowrate measurement.

Ultrasonic flow measurement was used to verify room cooler flowrates,

but was not relied on for operability determinations or cooler

-

performance calculations. The licensee stated that ultrasonic flow

measurement was no longer used due to difficulties installing the

equipment although procedures permitted its use as an option.

Enclosure 2

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,

Based on the information provided to the inspector, the inspector

concluded that flow sensor fouling was not contributing significant

errors to service water flow measurement.

,

E8.7 (Closed) Unresolved Item 50-413.414/94-17-16: Split Flow Orifice Flow

Resistance Factor

1

This Unresolved Item was Example 2 of Violation 94-17-02. SNSWP split

flow was addressed as part of the licensee's SNSWP reanalysis. The NRC

had issued a SER on November 19. 1996, accepting the licensee's

,

reanalysis.

E8.8 NRC Information Notice 92-18: Potential For Loss Of Remote Shutdown

a Capability During A Control Room Fire

1

'

Information Notice (IN) 92-18 alerted licensees of the potential for

loss of safe shutdown capability during a fire in the control room. The

IN reported that hot shorts occurring during the fire could potentially

cause the MOVs needed for safe shutdown to go to a stall condition.

This stall could result in valve and/or actuator damage that would

preclude use of the MOVs for shutdown.

The inspectors reviewed the licensee's April 8.1992, internal response

for IN 92-18 which concluded that a control room fire would not affect

Catawba's ability to open feedwater valves to provide safe shutdown.

The response indicated that the motors for the needed valves were wired

downstream of the control room, such that their operation from the safe

gutdownfacilitywouldnotbeadverselyaffectedbyacontrolroom

tire.

During the current inspectiori, the licensee stated that their original

determir.3 tion regarding the affects of a control room fire had been

reviewd and was still considered valid. However, they decided to

reexamine the issue relative to the impact of a fire in other areas.

such as the cable spreading room. The reexamination was initiated

,

through PIP 0-G97-0059.

E8.9 (Closed) IFI 50-413.414/96-02-01: Reliance on Testing of a Single Valve

to Support the Capabilities of a Group

This issue identified a concern that the licensee relied on the results

of a single test in establishing the thrust requirements for some groups

of GL 89-10 valves and that, in one instance, the adecuacy of even the

one test was uncertain. In a GL 89-10 assessment concucted during the

current inspection and documented in El.1 (Thrust Requirements for

Groups) above. the ins)ectors catermined that this issue was being

adequately addressed t1 rough al action item in PIP 0-C97-0421.

IFI 50-413.414/97-03-04 Actions to Address Weaknesses in GL 89-10

Implementation, was opened in Section E1.3 to track the licensee's

completion of this and other PIP actions.

Enclosure 2

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E8.10 (Closed) 50-413.41.4/96-02-02: Stem Coefficient of Friction for MOV  !

Opening Setting Calculations i

The issue identified by this item was evaluated during the current l

inspection, as described in Section E1.3 (Stem Friction Coefficient).  !

The issue was considered resolved through the licensee's increase of the 1

MOV opening stem friction coefficient value to 0.20 and the licensee's i

evaluation provided by PIP 0-C95-0879.

E8.11 (Closed) 50-413.414/96-02-03: MOV Opening Thrust Requirement

Uncertainties

The issue identified by this item was evaluated during the current

inspection. as described in Section E1.3 (Diagnostic Equipment

Uncertainties). The issue was considered resolved by the inspectors

through actions documented in PIPS 0-C95-0295 and -0879.

E8.12 (Closed) 50-413.414/96-02-04: Unpredictable Behavior Experienced in

Pressurizer PORV Block Valve MOV Testing

The issue identified by this item was that the prototype PORV block

valve tested by the licensee exhibited unpredictable behavior prior to i

flow isolation during a blowdown closing test. This test was conducted j

as part of the licensee's GL 89-10 program. In the current inspection, l

the inspectors reviewed a licensee engineering evaluation of this test, i

which was described in their "3-Inch Anchor Darling Double-Disk Gate

Valve Summary Test Report." The inspectors found that the report 1

provided satisfactory evidence that the unpredictable behavior exhibited

in the one test was due to a unique, unsatisfactory packing

configuration (not applicable to the licensee's installed valves). The i

inspectors considered the issue resolved.

IV. Plant Support

R2 Status of Radiological Protection and Control (RP&C) Facilities and

,

Equipment

R2.1 Comoliance with 10 CFR 70.24 Criticality Accident Reauirements

a. Insoection Scone (71750)

.

The inspector reviewed the licensee's compliance with 10 CFR 70.24

!

criticality accident requirements and associated PIP documentation in

i

'

response to the NRC staff's recent identification that several licensees

in the industry were not in conformance with the requirements of 10 CFR

70.24. nor had they been granted exemptions to this regulation.

Enclosure 2

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b. Observations and Findinas

Both Units at Catawba have radiation monitoring systems installed in the

new fuel unloading and storage areas. The inspector verified by

'

reviewing PIP documentation that the monitoring instrumentation meets 10

CFR 70.24(a) requirements (PIP 0-C97-0192). In addition to criticality

accident monitoring instrumentation and alarm capability requirements

the licensee is required by 10 CFR 70.24(a)(3) to have emergency <

procedures in place for evacuating personal when a criticality alarm J

sounds and to conduct evacuation drills. The licensee has not developed

procedures or conducted drills to meet the provisions of 10 CFR

70.24(a)(3). The licensee has initiated a corrective action as part of

the PIP referenced above to evaluate compliance with emergency procedure

requirements.

5

Both units at Catawba were previously granted exemptions from 10 CFR

70.24 requirements by the NRC staff as part of their special nuclear

material license during construction. The licensee did not submit a  :

request to continue the exemption when the special nuclear material

licenses expired upon issuance of operating licenses on January 17

1985, and May 15, 1986, for Unit 1 and Unit 2, respectively. The

licensee has not complied with the (a)(3) Sortion of the regulation

,

since these dates. On February 4, 1997, tie licensee submitted a

request for an exemption to the requirements of 10 CFR 70.24.

. c. Conclusions

4

The licensee has existing radiation monitoring systems installed in the

Unit 1 and Unit 2 new fuel unloading and storage areas which are capable 1

of alarming should an accidental criticality occur. The licensee has i

not developed emergency procedures or conducted drills to ensure  !

<

5

personnel are withdrawn to an area of safety when an alarm sounds. The '

failure to implement criticality accident emergency procedures and to

conduct evacuation drills is characterized as Violation 50-413.414/97-

03-02, Noncompliance with 10 CFR 70.24(a)(3) Criticality Accident

'

Requirements Regarding Evacuation Procedures and Drills. The licensee

<

has submitted a request to the NRC staff for an exemption to the

requirements of 70.24.

4

V. Manaaement Meetinas

X1 Exit Meetina Summarv

The inspectors ] resented the inspection results to members of licensee l

management at t1e conclusion of the inspection on February 20, 1997.

The licensee acknowledged the findings presented. No proprietary .

information was identified.  !

.

Enclosure 2

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PARTIAL LIST OF PERSONS CONTACTED

j Licensee

i Bhatnagar, A. , Operations Superintendent

Cline. T., Senior Technical Specialist, General Office Support

Coy, S., Radiation Protection Manager

Edwards, T., Valve Group Supervisor

Forbes, J., Engineering Manager

,

'

Harrall T. , IAE Maintenance Suparintendent

Helmers. C. . Engineer, Valve Group

Henkel H. , Engineer Valve Group

Kelly, C., Maintenance Manager

'

Kimball, D., Safety Review Group Manager

1 Kitlan, M.. Regulatory Compliance Manager

1

McCollum, W., Catawba Site Vice-President

'

Nicholson, K., Compliance Specialist

Peterson, G., Station Manager

'

Propst. R.. Chemistry Manager

'

Rogers, D.. Mechanical Maintenance Manager

Simril, J. , Engineer. Valve Group

Smith. C., MOV Program Lead, General Offico Support

,

Tower, D., Compliance Engineer

.

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INSPECTION PROCEDdRES USED

IP 37550: Engineering

-

IP 37551: Onsite Engineering

IP 40500: Self Assessment

l IP 61726: Surveillance Observation

IP 62707: Maintenance Observation

'

IP 71707: Plant Opera ~ ions

IP 71750: Plant Suppor *. Activities

IP 92902: Followup - Mcintenance

IP 92903

Followup - En 'ineering

. TI 2515/169: GL 89-10 MOV frogram Review

.

ITEMS OPENED. CLOSED. AND DISCUSSED

', Doened

i 50-413.414/97-03-01 VIO Failure to Follow Procedure for Receipt.

Inspection, and Control of 0A Condition

Materials., Parts, and Components (Section

E2.1)

50-413.414/97-03-02 VIO Noncompliance with 10 CFR 70.24(a)(3)

Criticality Accident Requirements

. Regarding Evacuation Procedures and Drills

. (Section R2.1)

! 50-414/97-03-03 NCV Mispositioned Nitrogen Backu) Supply

Valves Result in Degrading T1e Function of

! SG PORVs (Section M8.1)

50-413.414/97-03-04 IFI Actions to Address Weaknesses in GL 89-10

Implementation (Section El.3)

Closed

!

'

50-413.414/94-17-01 IFI Analysis of Skewed SNSWP Discharge Flow

. (Section E8.2)

4

'

50-413.414/94-17-02 VIO Failure to Properly Translate Regulatory

i Requirements into Specifications.

,

Drawings, and Procedures (Section E8.3)

'

50-413.414/94-17-03 IFI Short Discharge Leg Flow Verification

(Section E8.4)

50-413.414/94-17-10 IFI Flush Program Improvements (Section E8.5)

50-413.414/94-17-14 IFI Quantif.fing Flow Measurement Error

(Section E8.6)

'

Enclosure 2

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50-413.414/94-17-16 URI Split Flow Orifice Flow Resistance Factor

(Section E8.7)

50-414/96-20-01 URI Mispositioned Nitrogen Backup Supply

Valves Result in Degrading The Function of

Steam Generator Power Operated Relief

Valves (Section M8.1)

50-414/94-02, Rev 1 LER Reactor Trip Breakers Opened Due to

Component Failures (Section M8.2)

50-413.414/96-02-01 IFI Reliance on Testing of a Single Valve to  ;

Support the Capabilities of a Group

(Section E8.9)

50-413,414/96-02-02 IFI Stem Coefficient of Friction for MOV

Opening Setting Calculations (Section

E8.10)

50-413,414/96-02-03 IFI MOV Opening Thrust Requirement

4

Uncertainties (Section E8.11)

50-413,414/96-02-04 IFI Unpredictable Behavior Experienced in l

Pressurizer PORV Block Valve MOV Testing

(Section E8.12)

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Enclosure 2

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LIST OF ACRONYMS USED

'

ANSI -

American National Standards Institute

! CGD -

Commercial Grade Dedication

CFR -

Code of Federal Regulations

CNS -

Catawba Nuclear Station

DPC -

Duke Power Company

ECCS - Emergency Core Cooling System

EDG -

Emergency Diesel Generator

EDM -

Engineering Directives Manual

FSAR - Final Safety Analysis Report

GL -

Generic Letter

IAE -

Instrument and Electrical

IFI -

Inspector Fullowup Item

IR -

Inspection Report

IST -

In-Service Test

LER -

Licensee Event Report

MEPR - Major Equipment Problem Resolution

. MOV -

Motor Operated Valve

NCV -

Non-Cited Violation

NDE -

Non-Destructive Examination

'

NS -

Containment Spray System

NSRB - Nuclear Safety Review Board

NSM -

Nuclear Station Modification

.

0AC -

Operator Aide Computer

QA -

Quality Assurance

. OC -

Quality Control

,

PIP -

Problem Investigation Process

PORV - Power Operated Relief Valve

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4

RCS -

Reactor Coolant System

>

RG -

Regulatory Guide

RHR -

Resididual Heat Removal

,- RP&C - Radiological Protection & Control

RTB -

Reactor Trip Breaker

SER -

Safety Evaluation Report

~

SG -

Steam Generator

SNM -

Special Nuclear Material

SNSWP - Standby Nuclear Service Water Pond

SPDG - Spare Parts Diesel Generator

SSF -

Safe Shutdown Facility

SSPS - Solid S. ate Protection System

TDAFW - Turbine Driven Aux. Feedwater Pump

TEPR - Top Equioment Problem Resolution

TI -

Tem 3orary Instruction

l TS -

Tec1nical Specifications

. UFSAR - Updated Final Safety Analysis Report

i URI -

Unresolved item

US0 -

Unreviewed Safety Question

VIO -

Violation

WAPR - Top Plant Work-Around Problem Resolution

WO -

Work Order

i

Enclosure 2