ML20246J626

Insp Rept 50-219/89-16 on 890702-29.Violations Noted.Major Areas Inspected:Plant Operational Events,Control of High Radiation Areas,Evaluation of Plant Operation W/High Canal Water Temps & Security Response to Vital Area Door Problem

ML20246J626
Person / Time
Site:	Oyster Creek
Issue date:	08/18/1989
From:	Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20246J601	List: ML20246J596 ML20246J610 ML20246J626
References
50-219-89-16, IEB-87-002, IEB-87-2, NUDOCS 8909050222
Download: ML20246J626 (20)

See also: IR 05000219/1989016

Text

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2 U. S.' REGULATORY COMMISSTON

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REGION I.

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. Report'No. 50-219/89-16 l

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' Docket No.-50-219  !

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License No. DPR-16. Priority --- Category C. i

Licensee:- GPU Nuclear Corporation

.1 Upper Pond Road

Parsippany,- New Jersey 07054

Facility Name: Dyster Creek Nuclear Generating Station

Inspection Conducted: J_yly 2, 1989,'- July 29, 1989

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. Participating Inspectors: M. Banerjee, Resident Inspector -

S. Chaudhary, Senior Reactor Engineer

E. Collins, Senior Resident Inspector

H. Gregg, Senior Reactor Engineer

D. Lew, Resident-Inspector

Approved By: .A ror &7

Cowgill, Chief ./ 'Date  !

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eactor Projects'Section 4B l

Inspection Summary:

Inspection July 2 - July 29,1989 (Report No. 50-219/89-16) .

Areas Inspected: Inspection consisted of (234 hours0.00271 days <br />0.065 hours <br />3.869048e-4 weeks <br />8.9037e-5 months <br />) by resident and regional l

based. inspectors. The areas inspected included observation and review of plant  !

operational events (paragraph 2.0), corrective actions associated with the con- i

trol of high radiation areas (paragraph' 3.0), evaluation of plant operation j

with high canal water temperatures (paragraph 4.0), review of main transformer I

failures (paragraph 5.0), review of security response to vital area door '

problems (paragraph 6.0), surveillance observations (paragraph 7.0), observa-

tion of control rod drive pump motor insta11ation'(paragraph 8.0), evaluation

of testable check valve leakage test acceptance criteria (paragraph 9.0),

review of LER 89-15 (paragraph 10.0) and review of previously opened inspection

findings (paragraph 11.0).

Results: . Plant startup and operation on a temporcry transformer were performed

- with only minor problems. Overall, the plant was operated in a safe manner.

Problems continue to be experienced in the area of control of high radiation

8909050222 890824

PDR ADOCK 05000219

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areas. These problems are evidenced by nine events since August 1988. Most of.

these events involved the control of locked high radiation area doors.

Corrective actions were either untimely or ineffective. Prompt action is

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warranted to gain control of this problem and to identify' effective long-term

corrective steps. A notice of violation.is enclosed.

The technical evaluatica associated with operation of the plant with canal

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temperatures above 85 degrees was not completed one year after identification

by NRC inspectors in July 1988. Neither plant technical specifications nor

l plant procedures reflect 85 degrees as an operational limit, even though it is

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a design basis number and is used in the analysis of the plant response to the

design basis accident. Preliminary licensee evaluation, at the current reduced

power levels, shows torus temperature response ;? be acceptable with canal

temperatures up to 95 degrees. However, the licendae operated the plant at

temperatures above 85 degrees without performing a written safety evaluation.

A notice of violation is enclosed.

Two main transformer failures were apparently related and were brought on by a

combination of previous equipment deficiencies and maintenance performed during

the previous outage. 14 security violation.resulted in a vital door without

monitoring. Ti,ls violation will not be cited in a Notice of Violation because

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it was 1icensee identified and promptly corrected. Twelve previousiy opened

inspection findings were closed.

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TABLE OF CONTENTS .

Page

E1. 0 _ Li st of Peopl e Contacted . . . . . . . . . . . . . . . . . . . . .- 1

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'2.0- Review of Plant Operations .7 ................. 1

.2.1 '

Review of Operational Events. . . . . . . . . . . . . . . . 1

2.2 Control Room Observations . . . . . . . . . . . . . . . . . 3

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2. 3 Fa c i l i ty To urs . . . . . . . . . . . . . . . . . . . . . . . . 4-

a) Fire Protection. . . . . . . . . . . .. . . . . . . . . . 4

b) Equipment Control. . . . . . . . . . . . . . . . . . . . 4

c)iVital Instrumentation. . . . . . . . . . . . . . . . . . -4

d) Housekeeping . . . . . . . . . . . . . . . . . . . . . . 5

2. 4 : Summa ry . . . ' . . . ..................... 5

.5.6-ControlofHighRAdiation~ Areas................. 5

4.0 Canal Watec emperature. . -. . . . . . . . . . . . . . . . . . 7

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5. 0 Tra n s fo rme r Fa i l u re s . . . . . . . . . . . . . . . . . . . . . . 8 -

5.1 Review of Licensee Response to Transformer MIB Failure. . . 8

5.2 Cause of Failure. . ... . . . . . . . . . . . . . . . . . . 9

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6.0' Security . . . . . . . . -. . . . . . . . . . . . . . . . . . . . 9

' 7.0 Surveillance Observations. . . . . . . . . . . . . . . . . . . 10

7.1 Generator Load Reject ~. ..... . . . . . . . . . . . 10

7.2 Containment Spray and ESW Pump Operability and

Inservice' Test. . ....................10

. 8.0 Maintenance Observations . . . . . . . . . . . . . . . . . . . 10

9.0 Testable Check. Valve Leakage Tests . . . . . . . . . . . . . . 11

'10.0 Licensee Event Report. . . . . . . . . . . . . . . . . . . . . 12

' 11.0 Previously Open Inspection Findings. . . . . . . . . . . . . . 13

12.0 Exit Meeting . . . . . . . . . . . . . . . . . . . . . . . . . 17

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DETAILS

1,0 List of People Contacted

E. Fitzpatrick, Director Dyster Creek

G. Busch, Licensing Mgr.

K. Mulligan, Plant Operations

P. Crosby, Operations Engineer Supervisory

P. Cervenka, Operations Engineering

D. Jones, Electrical Engineer

D. Ranft, Elect /I&C/0PS

J. Frank, Plant Analysis

R. Farrell, Rad Engineer

R. Brown, Plant Operations Mgr.

R. Ewart, Security

K. Wolf, Rad Engineering Mgr.

P. Smith, Technical Functions

J. Lagatto, Technical Functions

J. Rogers, Licensing

A. Hawley, Operations Engineer

A. Rone, Director Plant Engineering

R. Fenti, QA Mod /0PS Mgr.

D. Mac Farlane, QA Site Audits Mgr.

R. Markowski, Quality Assurance

J. Solakiewicz, OPS QA Mgr.

P. Scallon, Radwaste Operations Mgr.

2.0 Review of Plant Operations (71707, 93702)

2.1 Review of Operational Events

The inspectors reviewed details associated with key operational

events that occurred during the report period. A summary of these

inspection activities follows.

Plant Trip

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On July 11, a fault in the M1B main transformer initiated a

generator / turbine trip and a reactor scram. At the time of the

fault, the plant was operating or, one main transformer because the

M1A main transformer had similarly failed on June 25 (Inspection

Report 50-219/89-14). The plant was operating at 57 percent of rated

thermal power.

The fault in the M1B main transformer caused more severe damage than

that by the M1A main transformer in June. The MIB main tr.msformer

had faults in all three phases and exhibited significant external

damage. The rapid increata in temperature and pressure caused by the

faults resulted in the si es of the transformer housing bulging

outward. The seam on one 2dge of the transformer housing cracked.

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011 was sprayed through the transformer relief valve and housing 1

crack. 'All three lightening arrestors were broken. The fire

protection system actuated; however, no fire occurred.

' The' transient on the plant was less severe than the previous trip

because the plant was operating at 57 percent _ power versus 100

percent. The maximum pressure attained during this transient was

1036 psig. As a result of the smaller pressure transient, the

isolation condensers did not initiate, the electromatic relief valves

did:not actuate and the recirculation pumps did not trip. These

systems did initiate during the June 25 trip.~ The plant responded

normally 'and as designed. Two control rods, however, were at

position 02 versus the fully . inserted position after the scram. The

inspector noted that the licensee satisfactorily completed testing on

these two control rods prior to startup.

The inspector attended the licensee's Post Trip Review Group (PTRG)

meeting. The overall conclusion from the PTRG was that the trip was

very similar to that which occurred on June 25. The. plant had

responded as. expected and the operators' response was very good. The

PTRG recommended that certain actions be completed prior to startup.

These actions included: (1) determining the potential adverse effects

on the plant's cr.d ,1CP&L's electrical systems, (2) evaluating the

possibility of a common mode failure mechanism which may affect the

replacement transformer, auxiliary or startup transformers or the

main gtnerator, (3) determining if any actions needed to be taken

prior t) returning the gencrator to service, and (4) performing sur-

veillance 617.4.010, . Trou';1eshooting Control Rod Drives' that Settle

at Position Oz rallowing a Reactor Scram, for control rods 18-23 and

30-19. These actions' were completed prior to startup. The inspector

had no questions about the plant's and operators' responses to the

transient.

Plant Startup

The licensee performed a plant startup on July 17. Th inspector

observed portions of the plant startup including the rod withdrawal

sequence, the heatup of the plant and the preshift brief. The

inspector noted that twenty four hour coverage was provided by plant

management during the startup.

One problem encountered during startup was a blown fuse in the

reactor manual control system (RMCS). This failure caused several

, rod block alarms and resulted in the inability to withdraw control

L rods. The licensee replaced the fuse; however, upon post maintenance

testing, the fuse blew again. After further troubleshooting, the

licensee determined that faulty thyristers in relay 4K3 were causing

the fuse to blow. The thyristers were replaced and no further pro-

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blems in the RSCS were encountered. The inspector had no questions

on the plant startup and heatup.

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l- Reactor Building to Torus Vacuum Breaker Differential Pressure

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Switches

During performance'of: a monthly surveillance test on 7/25/89 the ,

reactor building to_ torus.yacuum breaker differential pressure (dp)

switch 66A failed._to reset. Following-the requirements of the plant

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technical specification 3.5.4.C, the dp switch 66A was declared .in-

operable at-11:00:p.m. and a controlled shutdown initiated. The

switch was replaced and declared operable at 6:05 a.m. on the follow-

ing morning and-the shutdown was halted. The reactor _was then

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brought back to the administrative power limit corresponding-to.425

MWe.

The inspector reviewed _the switch failure'and licensee's immediate

corrective action. The inspector concluded that the licensee took

the appropriate action as required by the' plant ' technical specifi-

cations. This dp switch has a history of reset anomalies. IE

Bulletin 86-02-identified problems experienced at LaSalle and Oyster

-Creek with model 102 and 103 static iO'-ring (SOR) dp switches. The

dp switches ~66A and B,'and core spray booster pump dp switches RV-40

-A, B, C.and D are addressed by this IE Bulletin. RV 40 D switch had

failed to actuate during a surveillance in January 1989. With the

information provided in the IE Bulletin and recent switch failur;s,

the inspector was concerned about the reliability of these SOR pres-

-sure switches. The licensee is expediting the submittal of.a follow-

up response to the IE Bulletin and intends to imulement a plant modi-

fication which uses switches of a- different manufacturer.

2.2 Control Room Observations

Routine tours of the control room were conducted by the inspectors

during which time the following documents were reviewed:

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Control Room and Group Shift Supervisor's Logs;

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Technical Specification Log;

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Control Room and Shift Supervisor's Turnover Check Lists;

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Reactor Building and Turbine Building Tour Sheets;

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Equipment Control Logs;

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Standing Orders; and,

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Operational Memos and Directives.

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2.3 ' Facility Tours

Routine tears of the facility were conducted by the inspectors'to

make an assessment of the equipment conditions, personal safety, and

procedural adherence to regulatory requirements. The following areas

are among'those inspected:

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Turbine Building-

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Vital Switchgear Rooms

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Cable Spread!ng Room

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Diesel Generator Building

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Reactor Building

The following additional items were observed or verified:

a. Fire Protection:

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Randomly selected fire extinguishers were accessible and

inspected on schedule.

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Fire doors were unobstructed and in their proper position.

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Ignition sources and combustible materials were controlled

in accordance with the licensee's approved procedures.

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Appropriate fire watches or fire patrols.were stationed

when equipment was out of service,

b. Equipment Control:

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Jumper and equipment mark-ups did not conflict with

technical specification requirements.

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Conditions requiring the use of jumpers received the prompt

attention of the licensee.

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Administrative controls for the use of jumpers and

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equipment mark-ups were properly implemented.

c. Vital Instrumentation:

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Selected instruments appeared functional ano demonstrated

parameters within Technical Specification Limiting

Conditions for Operation.

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d. Housekeeping:

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Plant housekeeping and cleanliness were in accordance with

approved licensee programs.

No unacceptable conditions were:1dentified.

- 2.4 Summary

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Overall, plant operations were conducted in accordance with facility

procedures. The operator's response to the plant trip was.very good.

ine startup was' conducted .in e. nrderly fashion with only minor

equipment problems. No unacceptable conditions were identified.

3.0 Control of High Radiation Areas (71707, 92701)

Inspection Report 50-219/88-23 documented an event which occurred on

August 30, 1988, whereby a door to a high radiation area was left unlocked

and unattended. Immediate corrective actions for this event were taken;

however, a critique had not yet been completed at the time of the inspec-

tion. lhe incident was left unresolved (Unresolved Item 50-219/88-23-01)

pending.the results of a future review of.this event and other similar

events.

During this inspection period, a review was conducted on events since

August 1988 which involved uncontrolled / unguarded high radiation areas.

The inspector reviewed the circumstances surrounding these events as

documented in the licensee's radiological incident reports (RIRs) and

. critiques, and evaluated the effectiveness of the corrective actions.

Description of Events

Nine RIRs were generated by the licensee since August 30, 1988. During a

period of approximately ten months, seven incidents occurred in which

doors to high radiation areas were left unlocked and unattended, and two

incidents occurred in which high radiation areas were left unguarded.

Of the nine RIRs, the critiques associated with seven RIRs were available

for the inspector to review. One RIR determined that a critique was not

required because the cause of the incident was an equipment failure. The

critique associated with another RIR was not reviewed because, at the time

of the inspector's review, the licensee was not able to provide the in-

spector with the documentation of the critique because the responsible

engineer was on vacation.

The inspector noted that the causes for most of the events involved

personnel errors and were recurrent in nature. For example, RIR 88-023

documented an event in which a locked high radiation door was blocked

open 70 degrees. The licensee's investigation into the event failed to

conclusively determine a root cause; however, one possible contributing

cause was determined to be failure to physically challenge the door to

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ensure it was locked. The corrective action to address the problem of

personnel failing of physically challenge the door was to revise procedure  !

9300-ADM-4110.06, to include a positive listing of responsibilities of the

person who signs out the key. This proradure change has just recently

been implemented. In the interim, evenis had continued to occur in which

a contributing cause was the failure to adequately challenge the door.

These events were documented in RIRs89-003, 89-028 and 89-031. In RIRs89-003 and 89-028, the corrective actions included instructing personnel

involved in the need to physically check the door, and reiteration to

personnel of the requirements of procedure 9300-ADM-4110.06. In RIR

'89-031, the corrective action again stated the need to evaluate whether or

not procedure 9300-ADM-4110.06 should be rewritten to provide instructions

for physical challenges. Additionally, the licensee reemphasized to site

personnel the significance of the event and the proper methods and prac-

tices to ensure that doors are locked.

The inspector noted that some of the RIRs were not completed in a timely

manner. Procedure 9300-ADM-1201.01, Investigation of Radiological Inci-

dents, states the RIR should be completed by the responsible manager

within seven days of the date of receipt. RIR 89-028, which was issued on

April-28, 1989, documented an event in which the door to the New Rad Waste

fill aisle was left opened. The RIR was not completed until three months

later. RIR 89-008 was issued as a result of an event in which a high

radiation area was left unguarded. RIR 89-008 was not completed for over

a month after the event. RIR 89-031 was issued as a result of an event in

which the Regeneration Tank door was left unlocked and unattended. Though

the critique was completed within five days of receipt of the of the RIR,

the individual responsible for the critique noted that five days had

already elapsed between the time the event occurred and the RIR was

received. Because of this elapsed time, the recollection of parties in-

volved was less clear and some discussion of the incident among various

parties had already taken place. The lack of timeliness in the above

incidences impacted the effectiveness of the critiques and RIRs.

Some RIRs and the associated critiques were shallow. The root cause

identified in these RIRs was personnel error, and the corrective actions

were limited to personnel counselling and information to site personnel.

No long term effective corrective actions were identified in these RIRs.

Summary

In a period of approximately ten months, nine RIRs were generated to

document events involving uncontrolled high radiation areas. Actions to

preclude these occurrences have had minimal effect as evidenced by

continued incidents of similar causes. In some cases, the completion of

the RIR and implementation of corrective actions have not been timely. In

other cases, the RIRs and associated critiques were shallow and long term

corrective actions were not identified.

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NRC requirements, as specified in 10 CFR50, Appendix B, and the licensee's

requirements,.as.specified in their Operational Quality Assurance program,

require that measures be established to promptly identify and correct con-

ditions adverse to quality. The cause of significant conditions adverse

to quality shall be determined and appropriate action taken to prevent

recurrence. In the events involving the control of high radiation areas,

steps to prevent recurrence have not been adequate and have not reduced

the recurrence of these events. This is a violation. (50-219/89-16-01)-

4.0 Canal Water Temperature (71707,92701)

Inspection Report 50-219/88-23 describes an event in which the intake

canal water temperature exceeded 85 degrees F in July 1988. The Oyster

Creek Final Safety Analysis Report describes the containment spray /emer-

gency service water (ESW) heat exchanger to have a total heat removal

capacity of 50 million BTU /hr when supplied with 130 degrees F water from

the suppression pool and 85 degrees F sea water from the ESW system.'

Pending an evaluation for acceptability and deportability of plant opera-

tion with canal water temperature above 85 degrees, this item was left

unresolved (50-219/88-23-02).

In July 1989, a formal- safety evaluation had not been. finalized and thus

was not available for NRC review. Preliminary evaluation with 90 degrees

intake canal water temperature resulted in about a 1.5 degree increase in

peak torus water temperature. The impact of the increase in peak torus

water temperature on Core' Spray pump net positive suction head (NpSH) was

not formally evaluated. The completion of this evaluation was of low

priority due to low perceived safety significance.

On July 28, another preliminary evaluation of plant operation with canal

temperature above 85 degrees was performed. ~This analysis used 60%

reactor. power and 95 degrees canal temperature. Results showed peak torus

temperature to be about 142 degrees F. This peak is below the NPSH

requirement of 149.6 degrees F. for the most limiting core spray pump.

Further analysis is required to determine acceptability at 100% power.

These analysis will be documented in a written safety evaluation. Based en

these results, plant operation in the current configuration (about 70%

power) is acceptable.

The following conclusions were reached by the inspector:

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Failure to complete the safety evaluation in a timely manner resulted

in the plant being operated in an unanalyzed condition and

potentially outside the design basis as the ESW system is the

ultimate heat sink for core decay heat during a design basis LOCA.

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The licensee failed to report this event to the NRC.

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The licensee's low priority to complete the analysis resulted in a

repet' tion of the above event.

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' The margin for NPSH to the limiting Core Spray pump 1s very small,

thus, anyfincrease in the heat sink temperature above that used'in

the analysis is potentially safety significant and warrants' prompt i

evaluation.

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The torus temperature response curves _in the FSAR-update represent

two~ pump operation in one Containment Spray loop. The current system

~ design allows only one. pump to operate per. loop..

The license'e'.s procedures require performing a safety evaluation

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before performing plant modifications (hardware changes), procedure

changes, or new tests orfexperiments. However, the licensee's

procedures do not require performing a prompt = safety evaluation to

, determine' acceptability of plant operation when changes to the.

assumed parameters of the accident analysis occur. ,

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During July.1988 and July 1989, the plant was operated with elevated canal

. temperatures which resulted in.the plant being in an unanalyzed condition.

- 10 CFR Appendix B, Criterion XVI- requires that measures be established to  !

assure.that conditions adverse to quality are promptly identified and  !

corrected. After being; identified by the NRC, the-licensee.f411ed to-take i

..p rompt corrective' action in that, even after one year, an analysis was not  ;

completed to determine the safety of the plant while operating with ESW i

. temperature ~above 85. degrees F. This is a violation (50-219/89-16-02).  !

5.0.- Transformer Failures (71707)

5.1 Review of Licensee Response to Transformer M13 Failure

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Prior.to plant operations on the replacement transformer, Region I

management and resident inspectors met with the liceraee on July 13

to discuss their evaluation of transformer MIB failure. Transformer

M1A had failed on 6/25/89 (Inspection Report 50-219/89-14). The

scope and status of the licensee's review was presented.'

. Three areas of focus were identified by the licensee to be reviewed

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for potential problems. These were:. 1) the transformers

themselves,~2) equipment from the transformers out into the I

electrical distribution system, and 3) equipment from the

transformers into the plant.

In regard to the transformers themselves, the root cause of the

failure had not been determined, but it was thought that the fault

probably originated internal to the transformers and was related to

the maintenance performed during 12R outage.

In regard to plant equipment, it was concluded that the site

auxiliary transformer was not adversely affected. No work had been

performed on the startup transformers during the 12R outage, and they  !

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were not exposed to the faults in M1A or MIB. It was also concluded

that the station generator was not negatively impacted. Subsequent

internal inspection of the generator confirmed there was no loosening-

of.the generator stator.

-In' regard to the grid, an independent consultant reviewed the impact

of these transformer failures and identified.no problems.

. No unacceptable conditions were. identified.

5.2 Cause of Failure

The licensee's review of the failed transformers identified that l

during the 12R outage the cooling oil distribution boxes were dis-

covered split'and had been repaired. Also, a core sample from MIB

showed deteriorated insulation. It was concluded that long term ,

. operation of the transformers with inappropriate cooling oil distri- '

bution probably resulted in localized overheating of the coils. This

overheating led to accelerated de0radation and embrittlement of wind -

ing insulation. This effect, combined with the coil movement during

12R outage and vibration-from operation caut.ed the transformer

failures. The~11censee's efforts are continuing with regard to'the i

transformer failures. i

- 6.0 Security Event (71707,93702)

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On July 11, the licensee failed to take adequate compensatory actions for i

a failed alarm on a door to an unoccupied vital area. The failure to take

adequate compensatory actions was not discovered by the licensee until

five hours later. The inspector reviewed the circumstances surrounding

and the licensee's conclusions on this event. _

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Although security personnel immediately responded to the failed alarm, l

full compensatory action for the circumstances was not accomplished for -l

over five hours. When discovered by the licensee appropriate actions to i

ensure that no unauthorized entry occurred were taken and the event was

properly reported to the NRC per 10 CFR 73.71. j

The licensee's review determined the causes of this event to be (1) weak

communication among the security personnel, (2) insufficient followup by  !

the on-duty Shift Commander, and (3) knowledge deficiencies by some in-

dividuals on the requirements for vital area protection and the operation

of security equipment. The licensee initiated retraining of certain in-  ;

dividuals, emphasized the need for proper communications and upgraded the  !

requirements for security personnel training. The inspector questioned l

the licensee on the proper use of procedures. The licensee believed  !

responding to these alarms is a frequent evolution with which security

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.' personnel are familiar. The requirements for unoccupied vital areas

should be very basic knowledge to security personnel. The inspector had

no-further questions.

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Failure'to provide adequate compensatory action for inoperable intrusion

o . detection system equipment for a vital barrier door is a violation. This

violation is 'not being cited because the criteria specified in'Section V.A

of the Enforcement Policy were satisfied. (NV89-16-03)

7.0 Surveillance Observations (61726)

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7.1 Generator Load Reject

The inspector observed portions of the turbine generator load rejec-

tion scram test. The surveillance procedure was reviewed for confor-

mance with the technical specifications and proper approval for test

performance. The test instrumentation was- verified to be properly

calibrated. The technicians performing the surveillance were know -

ledgeable about the test procedure, system being affected and

expected results. The test results were within acceptance criteria.

The inspector reviewed the-completed test results and historical

results from previous tests. It appeared th6t some pressure switches

(Barksdale model B2T-M12SS) have experienced substantial setpoint

drift mostly in the conservative direction. The licensae indicated

theLuse of this type of Barksdale pressure switenes is being phased

out. The inspector had no further questions regarding pressure

switch reliability.

7.2 Containment Spray and ESW Pump-Operability and Inservice Test

The licensee conducted surveillance procedure 607.4.005, Containment

Spray and Emergency' Water Service Water Pump System 2 Operability and

Inservice Test, on July 17. This surveillance verifies the operabi-

lity of the pumps and selected valves in the Containment Spray and

Emergency Service Water System.

The inspector observed portions of the surveillance. The operation

of the pumps and valves were observed both locally and in the control

room. Instrumentation readings were verified with those recorded on

the data' sheet. The data results were verified to be within the

acceptance criteria of the surveillance. Conditions of the plant

were verified to ensure that technical specifications were satisfied.

The inspector had no questions on the performance of the surveil-

lance.

6.0 Maintenance Observations (62703)  ;

On July 2, the B control rod drive (CRD) pump motor failed. The licensee

determined the failure was at the motor leads, which became virtually

detached from the motor winding. This failure was attributed to poor

workmanship of the vendor, G.E., who repaired the motor leads during

January 1988 subsequent to a previous failure in December 1987.

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The immediate corrective action was to replace the failed motor with a

refurbished motor. The refurbished motor was repaired by G.E. subsequent

to its failure in March 1989. This failure was attributed to a loose

deflector plate. The deflector plate became loose and settled on the

moter winding, thus shorting the motor.

-The July 2 motor failure was documented in a deviation report wnich has

not been closed out as of the end of the inspection period. The inspector

questioned the licensee about the possibility of other safety related

motors having loose deflector plates or degraded leads. The licensee

considers the deflector plate failure to be an isolated case and is

evaluating the cause of the degraded leads.

The inspector observed portions of the installation of CRD pump motor.

Necessary approvals were obtained prior to initiation of the work, the

equipment tagout was appropriate, the work sequence was according to the

approved procedure, and quality control hold points were appropriately

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established for motor installation.

It was observed that this work was performed on a general Radiation Work

Permit (RWP). A review of the job was performed by radiological controls

personnel to determine if a job specific RWP was required. Based on this

review, a determination was made that no job specific RWP was required.

The inspector had no other questions related to the motor installation.

9.0 Core Spray Testable Check Valve Leak Test (61726, 71707)

During an inspector's review of procedure 610.4.008, Core Spray Testable

Check Valve Leakage and In-Service Test, the consistency between the

procedure's acceptance criteria and the technical specification require-

ment was questioned. Technical specifications indicated that the

acceptance criteria for valve leakage was five gallons per minute (gpm).

The inspectors interpreted the five gpm limit as corresponding to leakage

at normal operating pressure (approximately 1020 psig). The surveillance,

however, is performed prior to plant pressure reaching 600 psig. The

measured leakage at the lower test pressure is compared to the technical

specification leakage limit. The measured leakage is not pressure

adjusted prior to comparing it to the acceptance criteria.

The licensee stated that the leakage requirement for the core spray test-

able check valves was written by the NRC and incorporated into technical

specification via an order for modification of license issued in 1981.

The licensee further stated that the literal reading of the technical

specification indicated no requirement to perform pressure adjustments to

the measured leakage; and, therefore such adjustments were not considered.

The inspectors pointed out that when the order for modification was issued

to Oyster Creek, the technical evaluation report performed by the Franklin ,

Research Center was enclosed as an attachment. The report states when l

leakee tests are made using pressures less than function maximum pressure

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' differential (i.e., normal operating pressure), the observed leakage shall

be adjusted to function maximum pressure differential value. The report

further states that the adjustment shall be' calculated assuming leakage to

be proportional to the pressure differential to the one-half power.

Although the technical specifications do not' delineate the requirement to

pressure adjust or specify that the five gpm leakage criterion is applic-

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able:to function maximum pressure differential pressure, the intent as

evidenced from the attached technical evaluation report was to perform

. pressure adjustments.

'The licensee is making procedural changes to the surveillance to incorporate

the pressure adjustment. The inspectors noted that previously measured

leakage rates were well within the acceptance criteria even after thi

pressure adjustments were made to the observed leakage. The inspecto6

concluded that although the technical specifications did not specify the

requirements for pressure adjustments, the licensee conservatively decided

to change their. procedures once the original intent was understood. The

inspectors.have no further questions concerning the surveillance acceptance

criteria.

10.0 Licensee Event Report (92720)

LER 89-15 described the main generator over excitation event on May 18,

1989, which'resulted in a generator trip, reactor scram, but did not auto-

matically transfer power to the startup transformers. This event and

licensee's corrective action were reviewed in Inspection Report 50-219/

89-12. The licensee committed, in a phone conversation with NRC Region I,

to evaluate the need for modifying the plant such that the Start Up

transformers would automatically energize the 4160 volt buses following an

over-excitation trip, in addition to improving administrative controls and

communication during maintenance and surveillance activities.

l The Dyster Creek Facility Description and Safety Analysis Report (FDSAR)

L Section VIII-2-1, states "upon loss of the station generator during normal

operation, the power requirements are automatically transferred to the

startup transformers ". However, during the event, when the station

generator was lost due to operator error, automatic transfer to the

startup transformers did not occur. This resulted in a power loss to the

4160 V-buses, a loss of 1A and IB reactor feed pumps, and an automatic

initiation of the Emergency Diesel Generators. The inspector could not

l establish, from this sentence in the FDSAR, the existence of an original

l licensee commitment _to require the over-excitation trip to automatically

transfer site loads to the start-up transformers.

In the LER, the licensee did not state the commitment to evaluate the need

for modifying the plant design. The inspector questioned the licensee

regarding the status and validity of this commitment. The licensei

restated their commitment to perform this evaluation and is currently

implementing the scoping effort into the budget.

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11.0 Previously Open-Inspection Findings (92701, 92702, 92703, 25027)

(Closed) 10 CFR 21 Report 86-88-01. Conval ball stop check valve defect

preventing proper closure.

The licensee's letter of 7/26/86 notified the NRC of a defect which pre-

vented the proper' closure of the valve due to the' ball lodging-inside the

. spring. The inspector determined that 50 of_these valves were purchased

as substitutes for control rod drive (CRD) ' system valves V-106. - The

vendor subsequently designed a modification which added a- spring (,dide

part at the ball / spring interface to prevent the ball from. entering the

spring.

The inspector verified that the licensee's Plant. Engineering.and. Technical

Function Departments reviewed and accepted the modification as. documented

in the' Material Nonconformance Report (MNCR 86-0255). The inspector also

verified that all 50 valves were modified prior ~to installation in the CRD

system. The inspector noted that the licensee was the sole purchaser of

this valve. This item is closed.

(Closed) Unresolved Item 87-04-03. Damaged Core Spray System Hydraulic

Snubbers.

This item was opened as a result of several unanswered questions pertain-

ing.to damaged snubbers NZ-2-S6 and NZ-2-S10. Snubber NZ-2-S6 was found

with a bent threaded rod and'a 1/8" base plate. gap. Snubber NZ-2-S10 was

found with a bent rod, a partially displaced spherical bushing, a loose

turnbuckle jam nut and a loose sleeve type anchor bolt. The unanswered

questions included: (1) the cause of damage; (2) means to prevent

spherical bushing displacement; (3) testing for jam nut tightness; and (4)-

resolution of base plate gaps and loose anchor bolts.

The inspector reviewed the licensee's response to each question. Through

testing of the snubbers and evaluation of video tapes of snubbers during

system testing, the licensee concluded that the snubbers were not damaged

through system operations but were damaged by personnel conducting

maintenance in the area. The licensee revised both the hydraulic and

mechanical snubber inspection procedures (675.1.001, Rev.16 and

-A100-GMM-3921.52, Rev. 1) to limit the clearance of the paddle and clevis

space. This limitation would prevent spherical bushing displacement.

Quality Control (QC) and Maintenance, Facility and Construction (MC&F)

departments took appropriate action to specify the adequate testing for

jam nut tightness. The inspect r verified that the bolts in tension had a

5.4 factor of safety and that the plate bending stress was within

allowable limits as documented in Material Non Conformance Report (MNCR)86-999 and Technical Function's Calculation C-1302-212-5320-021. The

inspector also noted in MNCR 86-968 that the 1/8" base plate gap at

snubber NZ-2-S6 was shimmed. This item is closed.

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{ Closed) Violation 87-07-01. Failure to Show Piping Modification on

Dr2 wing.

.Two removable blind spectacle' flanges, Y-1-57 and Y-1-58, were installed'

to' eliminate the need for several isolation valves. One of the drawings

depicting this piping, Dwg. GE 237E726 Revision 39, did not reflect the

modification.

The inspector reviewed the licensee's response of 5/14/87 and verified

that the described corrective actions were perform d. Drafting standard

DS-002 Rev. 2 was revised to require construction c.awings to note all

other affected drawings. The inspector also verified that drawing GE

237E726, Revision 45, was updated to include the spectacle flanges. This

item is closed.

(Closed) Unresolved Item 87-08-02. Review of licensee's explanation of

corrective actions takea for two system core spray snubbers erroneously

deleted from the snubber list.

The inspector reviewed Licensee Event Report (LER)87-017, which pertained

to this item. The LER defined the omission as personnel error. The

-licensee's review of the safety significance of the issue was based on a

worst case analysis with both snubbers considered inoperable. The review

determined core spray system operability would not be affected. The

inspector verified that the licensee's current procedure A100-GMM-3921.52,

" Removal, Inspection and Installation of Mechanical Snubbers," and the

piping isometric drawings have been revised to include the previously-

omitted snubbers. This item is closed.

(Closed) Unresolved Item 87-08-03. Resolution of Damaged Supports on

Core Spray System and Full Flow Test Lines.

The inspector reviewed the licensee's Safety Evalc-i.on SE 212-004 and

verified that the unresolved item concerns were adequately addressed. The

evaluation which considered seismic operability with degraded supports,

determined that the IE Bulletin 79-02/14 calculations would still be valid

and that the highest core spray piping stress is less than the allowable

stress. Fatigue calculations were performed on core spray system 2, the

bounding system, because it had more movement and support damage. The

computer code model was backfitted with the 3" piping displacement as

determined from piping scrape marks. The results demonstrated there was

no significant fatigue reduction. Interferences that could restrict piping

movement were conservatively modeled as new restraints, and the computer

code was rerun to assure the conditions were bounded. The licensee's

evaluations were appropriate. This item is closed.

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(Closed)' NRC Bulletin BU-87-02. Fastener Testing to Determine Material

Conformance.

This bulletin required the licensee (1) to review its receipt inspection

requirements and internal controis in fasteners and (2) independently

determine, through testing, whether fasteners in stores at their

facilities met required mechanical and chemical specification

requirements.

The licensee submitted responses to the bulletin on 2/26/88. The 2/26/88

submittal addressed each action required by the. bulletin. Additional

information, which was requested in the supplements, was submitted by the

licensee on 7/25/88.

The inspector evaluated the licensee's responses and determined that each

of the bulletin requirements was appropriately addressed. The inspector

noted that of-the 40 fasteners tested (20 safety related and 20 non-safety

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related), five were out of specification. Of the five fasteners only one

was a safety related item.

The inspector reviewed the Material Non Conformance Reports, and the-

licensee's evaluation and disposition of each of the five out of specifi-

cation fasteners. The one safety related fastener (OC-002) had higher

than allowable hardness. Of the 250 0C-002 fasteners purchased, 50 were

used'in a non-safety related application and were evaluated to be accept-

able. .The remaining 200 were scrapped. The four non-safety related

fasteners were evaluated as follows: (1) fastener OC-022 was minimally

out of specification for carbon content and was evaluated as acceptable

because the mechanical prorerties were met; (2) fastener 0C-021 which had

high hardness was evaluated to be acceptable where used, and the remaining

stock was scrapped; (3) fastener 0C-023 which also had high hardness was

evaluated to be acceptable for use; and (4)' fastener DC-038 which had low

hardness was evaluated as acceptable where used, and the remaining stock

was scrapped.

The licensee's response to item 6 of the bulletin stated it had a' program

to assure quality of fasteners since 1986. The program verified the sample

testing of raw materials and simple fabricated parts. The inspector noted

that the licensee had verified the sample testing of 327 items since late

1985. Of these items 164 were fasteners. Thir, item is closed.

(Closed) Unresolved Item 86-24-03. This item is related to the

licensee's seismic analysis of piping. The analysis did not combine

closely spaced modes as recommended in Reg. Guide 1.92, and the piping

analysis indicated pipe stresses higher than allowable by governing code.

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The above analysis which showed overstress condition was performed.

manually.by span-table techniques. The licensee has reanalyzed the' piping

using dynamic analysis by computer,- applying simultaneously two. horizontal

and one vertical seismic' accelerations, which combines closely spaced

modes as-recommended by Reg. Guide 1.92. The above approach is-conserva-

tive and much more rigorous than the original analysis. This item is

closed.

'(Closed) Unresolved Item 86-38-05. This item is related to the drywell

thinning problems. The licensee has implemented a long range monitoring

program and resolution of:this problem. This problem is being tracked by

several other open items by NRC. Therefore, to consolidate the tracking '

as one item this item is closed. The item tracking the above problem is

89-01-01.

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(Closed) Violation 88-15-01. This item pertains to the licensee's

acceptance of overstressed piping. A time-history analysis of the system

. indicated approximately 50% reduction in the calculated stresses compared

to the analysis documented in MPR-999, Rev. 1. The reanalysis confirmed

that there was no safety concern and the design margin was maintained.

This item is closed.

(Closed) Unresolved' Item'88-81-01. This item pertained to discrepant

conditions of several pipe supports identified by the NRC. The licensee's

resolution of:the'above concerns was reviewed and evaluated by the NRC,

.and were documented in the Inspection Report.50-219/89-01, paragraph 5.0.

Based on the above review, this item is closed.

(0 pen) Unresolved Item 86-30-01. This item was reviewed by the NRC in

Inspection Report 50-219/87-07 and was left open pending the licensee's

actions in regard to . final engineering evaluation and implementation of

the crack monitoring program proposed by the licensee.

The. licensee informed the inspector that a monitoring program has been

implemented by Installation of optical monitoring devices, and a number of

these monitors have been read in the past year. However, the licensee's

engineers feel that sufficient data over a long period of time has not

been accumulated to determine the validity of observation and a meaningful

technical analysis. The licensee is currently in the process of

formalizing the monitoring program for inclusion in the plant ISI program

L for regular observation and data acquisition. The item remains open

pending implementation of a formalized ISI monitoring program by the

licensee.

L (0 pen) Unresolved Item 89-01-01. This item pertains to the problem of

drywell thinning. The licensee is continuing to monitor and evaluate the

progress of the corrective measures and engineering evaluation. This item

remains open pending the resolution of the problem and review by the NRC

of the actions by the licensee in this regard.

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(Closed) Unresolved-Item 88-23-01. This item is addressed in paragraph

'3.0 of-this inspection report. .This item is closed based upon issuance of

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violation 50-219/89-16-01.

(Closed Unresolved: Item 88-23-02. This item is addressed in ' paragraph' 4.0

of this inspection report. This item is closed based upon issuance of

violation 50-219/89-16-02.

-12.0 Exit Interview-(30703)

A summary of the results of the inspection activities performed during

this report period were made at meetings with senior licensee management

at the end of this inspection. The licensee stated that, of the subjects

discussed at the exit interview, no proprietary information was included.

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