IR 05000440/1990008

Safety Insp Rept 50-440/90-08 on 900416-0611.Violations Noted.Major Areas Inspected:Licensee Action on Previous Insp Items,Independent Safety Engineering Group,Info Notice,Ler & SER Followups & Monthly Surveillance Observation

ML20055E032
Person / Time
Site:	Perry
Issue date:	06/29/1990
From:	Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20055E031	List: IR 05000440/1990008 ML20055E029
References
TASK-1.B.1.2, TASK-2.E.4.1, TASK-TM 50-440-90-08, 50-440-90-8, GL-89-04, GL-89-4, IEIN-88-024, IEIN-88-24, NUDOCS 9007100297
Download: ML20055E032 (26)

Text

--

.

,

..

,

,

h-

Q-.

'

,,

U.S. NUCLEAR REGULATORY COMMISSION l' '

'

REGION III

i

'

\\

Repert No. 50-440/90008(DRP)

Docket No. 50-440 License No. NPF-58 j

l

. Licensee:

Cleveland Electric Illuminating Company

Post Office Box 5000 Cleveland, OH 44101

'

Facility Name: Perry Nuclear Power Plant l

Inspection At: Perry Site, Perry, Ohio j

Inspection Conducted: April 16, through June 11, 1990 i

-r Inspectors:

P. L. Hiland

G. F. O'

yer j

Approved ByL L

hief L,l ft SC Reactor Projects Section 3B Date

o Inspection Summary l

,

Inspection on April 16 through June 11. 1990 (Report No.' 50-440/90008(DRP))

' Areas Inspected:

Routine, unannounced safety inspection by resident inspectors of. licensee action on previous inspection items; independent safety engineering group; information notice followup; licensec event report followup; safety evaluation report followup; monthly surveillance observation;

mont_hly maintenance observations; operational safety verification; review of plant modifications; onsite followup of events; evaluation of self-assessment capability;~and' plant status meeting.

Results:

Of the twelve areas inspected, two non-cited violations were

,

identified.

First, in the area of licensee event report followup (Paragraph 5.), a violation of-technical specifications concerning gaseous

!

effluent monitoring was identified. Second, in the area of monthly

'

surveillance observations (Paragraph 7.a.). a violation concerning personnel l

n failure to follow procedures was identified.

Both of these. violations were identified by the licensee with appropriate response.and corrective actions; therefore, a Notice of Violation was not issued.

t For this report period, the area of plant operations was considered a strength based on routine observations of plant evolutions and the inspectors' review of operator response to events. The area of maintenance and surveillance activities was considered adequate.

The inspectors considered the licensee's 9007100297 900629 FDR ADOCK 0500044o PDC

_

,7

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

_ - _ -

- _ - -

- - - - -

y,i y

,

\\'-

/ -

n s

response, once identified, to an improperly performed surveillance of emergency service water, to be prompt and appropriate.

The area of safety assessment / quality verification was considered a strength based on the inspectors review of activities performed by the licensee's onsite review-

committee and the independent safety engineering group.

In addition, the inspectors found the licensee's followup activities and corrective actions stated in nonroutine event reports, condition reports, and responses to

+

violations-to be completed as stated, Iy

In general, the inspectors found the areas of radiological controls and security to be a strength based on routine observations of these activities.

Also, the area of emergency preparedness was considered a strength based on-

[.

the inspectors observations during a training exercise.

.;

!M

,.

t

,

b.

1.

-

.

.

...

-

-

- -

-

O

'

<

F

.

i.

-'

} 2.-.

,

.

DETAILS 1.

Persons Contacted a.

Cleveland Electric Illuminating Company (CEI)

,

L

1. M. Lyster, Vice President, Nuclear-Perry

• R. Stratman, General Manager, Perry Nuclear Power Plant (PNPP)

• M. Gmyreck, Operations Manager, PNPP

1. M. Cohen, Manager Maintenance Department, PNPP

1. D. Cobb, Operations Superintendent, PNPP

1. S. Kensicki, Director, Perry Nuclear Engineering Department (PNED)

1. V..Concel, Manager, Technical Section, PNED

1. aH. Hegrat, Compliance Engineer, Perry Nuclear Support Department (PNSD)

1. • R. Newkirk, Manager, Licensing and Compliance Section, PNSD

• E. Riley, Director, Perry Nuclear Quality Assurance Department (PNQAD)

b.

U. S. Nuclear Regulatory Commission

1. R. Knop, Chief Branch 3, Division of Rea:: tor Projects

1. M. Ring, Chief, Engineering Branch, Division of Reactor Safety

1. • P. Hiland, Senior Resident Inspector, RIII

• G. O'Dwyer, Resident Inspector, RIII

1. T. Colburn, Perry Project Manager, NRR

1. B. Drouin, Reactor Engineer, RIII

1. M. Liu, Reactor Inspector, RIII

1. Denotes those attending the management meeting on April. 17, 1990.

• Denotes those attending the exit meeting held on June 11, 1990.

2.

Licensee Action on Previous Inspection Findings (92701)(92702)

a.

(Closed) 10 CFR Part 21 Report (440/87002-PP(DRP)):

General

,

Electric HFA relays with latching mechanisms.

This item was

'

initially reviewed by the inspectors in Inspection Report 50-440/87023,- dated February.2, 1988, Paragraph 4.

At the conclusion of that review, this item remained open pending

.i completion of licensee action in response to the subject j

notification.

l As detailed in General Electric service advice. letter (SAL)

Number 190.1 dated November 16, 1987, a reportable condition was identified related to HFA auxiliary relays.

The condition identified'was an insufficient latch engagement that could cause the affected relays to unlatch incorrectly.

Subsequent to receipt of the subject notification, the licensee evaluated the reportable

'

condition for its applicability to the Perry plant.

The licensee identified eight non-safety HFA latching relays of the type described in the notification.

Six were in warehouse storage and i

two were installed in plant control panels.

L I

.

i y

_

__

.J

_

.is

,

• s The inspectors reviewed closed work orders 88-1187, 88-1188, and 88-1229 which documented the licensee's actions to inspect and rework the eight affected relays.

Based on the inspectors review

of actions taken by the licensee which included an evaluation of applicability to the Perry plant and completion of corrective

!

actions as directed by SAL 190.1, this item is closed.

b.

(Closed) Open Item (440/87005-02(DRP)):

Change value of Top of Active Fuel (TAF) to 0 inches.

This item was initially identified i

in Inspection Report 50-440/87005, dated April 1,1987.

The purpose of the-subject item was to assure inspector followup of licensee improvements to the Perry emergency procedures. _However, Open Item 440/89022-06 was identified by the inspectors following the i

,

licensee's response to the NRC Diagnostic Evaluation Team (OET).

!

report dated May 1989.

The latter open item (440/89022-06)

encompasses the issue originally identified in the subject item.

!

'Therefore, the subject item is closed and followup review of improvements to the Perry emergency procedures will be documented

under Open Item 440/89022-06.

i i

c.

(Closed)UnresolvedItem(440/88004-01(DRP)): Threaded pipe caps

.

installed as sealing device on drywell penetrations. During a tour i

of containment, the inspectors noted that the licensee had-installed

threaded pipe caps on drywell penetration isolation valves such as vents, drains, and test connections.

The licensee considered the j

threaded pipe caps to be " sealed blind flanges;" therefore, the

,

required Technical Specification surveillance of verifying valves

!

closed every COLD SHUTDOWN was performed in lieu of.a monthly-surveillance. At the time of initial review, the inspectors questioned the licensee's basis for not performing monthly inspections.

During this report period, the inspectors reviewed licensee Condition Report (CR)88-087, dated June 30, 1988. That approved CR documented the licensee's evaluation of the adequacy of surveillance activities on the containment and drywell penetrations. As stated in CR 88-087, the licensee defined the drywell penetration test connection threaded caps as " sealed blind flanges." Technical Specification 4.6.2.1.a allowed a less frequent (each COLD SHUTDOWN)

surveillance interval on blind flanges located inside the containment or drywell.

The inspectors concluded that the licensee's evaluation and treatment of drywell test connection threaded pipe caps as " sealed blind flanges" was reasonable.

Since the Perry plant incorporates a Mark III containment design, the inspectors noted that drywell bypass leakage limits were contained in Technical Specification 3.6.2.2.

Degradation of threaded pipe caps used as " sealed blind ilanges" should be identified-through the 18 month required surveillance test of drywell bypass leakage. Based on the inspectors review as discussed above, this item is closed.

-

_

-

_

_

_

%

.

,..

.

D

d.

(Closed) Violation (440/88012-01(DRP)):

Failure to implement instructions for shutdown cooling system fill and vent operation.

During an NRC Operational Safety Team Inspection (OSTI), the inspectors observed two instances of failure to use an existing written instruction in order to properly fill and vent system piping.

The licensee responded to the subject violation in letter

PY-CEI/NRR-0926L, dated October 19, 1988,- in a timely manner. As

!

stated in that response, the licensee identified the root cause for

.

the subject violation to be insufficient emphasis toward procedural

!

compliance and a lack of direct supervisory involvement in

-

evolutions performed outside the control room.

Corrective actions

taken by the licensee includ6d counseling of personnel directly involved in the subject violation and increasing the supervisory

attention toward plant evolutions performed by non-licensed

operations personnel.

In addition, the licensee stated that i

improved procedural compliance was emphasized during requalification training on current events.

v The inspectors concluded that the licensee's root cause

determination was correct and the corrective actions were

~

appropriate.

The corrective actions appeared effective in that similar violations have not been identified.

The inspectors noted that recent violations of prccedural use have been due to a lack of

" attention to detail" versus the subject violation failure to use existing procedures. Based on the corrective action taken by the licensee and the apparent effectiveness of that corrective action, this' item is closed..

e.

(Closed) Unresolved Item (440/88012-04(DRP)):

Technical justification for revising design basis. maximum temperature of the

. ultimate heat sink.

During unseasonably warm weather in July-August 1988,-higher than normal Lake Erie water temperatures were measured at the licensee's emergency service water' intake structure. Since the measured temperatures approached the 80 degree Fahrenheit ('F)

design basis for the Perry plant's ultimate heat sink, the licensee performed an analysis which concluded that ultimate heat sink temperature could increase to 85'F.

The results of that analysis were documented in PNPP Change Request-(CR) No.88-259 dated August 23, 1988.

i

,

i

'

The inspectors review of the licensee's technical justification was previously documented in Inspection Report 50-440/88012, dated September 14, 1988, Paragraph 8.a.

However, at the conclusion of that inspection effort, the inspectors were concerned that the analysis performed by the licensee was not timely.

During this report period, the inspectors reviewed historical documentation of actions taken by the licensee:

)

J

c l

.

'

i

.-,

'

i (1) Licensee Field Change Request (FCR) 10090 was initiated

July 1, 1988, by plant personnel due to-increasing Lake Erie temN eatures.

The engineering response to FCR 10090 was

,rovided July 28, 1988, which provided required flow rates

and limiting temperatures for equipment loads serviced by

the ultimate heat sink.

,

(2) Licensee CR 88-187, dated August 5,1988, was initiated to

"

resolve temperature increase concerns and potential plant

operation outside design basis information. On August 5, 1988,

the licensee's initial. engineering review did not conclude that

!

plant operation was outside design basis limits.

(3) Licensee CR 88-259, dated August 23, 1988, contained General

"

Electric letter PY-GEN /CEI-2849 dated August 17, 1988. That vendor letter responded to the licensee's request for an assessment of impact of changes in various Technical Specification temperature values.

Based on review of the above documentation, the inspectors concluded that the timeliness of licensee actions was reasonable.

The initial decisions appeared to have been made based on the best available information.

The safety evaluation which supported a change to the Updated Safety Analysis Report (USAR) to raise the design basis ultimate heat sink temperature to 85'F appeared to have been completed in a reasonable time when the inspectors considered the necessary detail and required support from the original design engineer (General Electric). This item is closed, f.

'(Closed) Open Item-(440/88015-01(DRP)):

Cracking of welds on TransAmerican DeLaval Inc, (TDI) diesel generator intercooler adapter guide vanes. As previously documented in Inspection Report 50-440/88015, dated November 10, 1988, Paragraph 4, the

,

licensee had been advised of potential cracking and failure of welds

which secured guido vanes to the emergency diesel generator intercooler adapter housing. At the time of that inspection, the licensee had scheduled to perform the necessary inspection of guide vane attachment welds.

During this report period, the inspectors reviewed licensee Work Orders 87-5069 and 88-7668.

Those work orders documented the L

performance of inspection activities on the guide vane welds for the l

Perry Division I and II emergency diesel generators. The inspection results indicated some weld defects; however, the weld defects had not progressed to a failure stage.

The baffles were removed and new baffle plates were installed in accordance with Design Change l:

Package (DCP)86-965.

Based on completion of the subject inspection and corrective actions, this item is closed.

,

i i

'

'

i

_

s

.

.

,

,,

• .

.

e e

.

.-

L r

g-

-(Closed)OpenItem(440/88015-02(DRP)):

Instrument inaccuracy due

.

to offset. A positive offset of approximately 50 percent of full scale existed on the "B" Steam Jet Air Ejector ($JAE) steam supply

flow indication switch (IN62-N102A) even in the absence of any steam flow.- It could therefore have prevented the switch's

automatic isolation signal (on low dilution steam flow) which

'

protected against the accumulation of excessive concentrations of

.

hydrogen in the offgas system.

The malfunction of low dilution steam flow was analyzed in section 11.3 and Table 11.3-4 of the Updated Safety Analysis Report. The licensee responded to this i

item in letter PY-CEI/01E-0356L, dated August 10, 1989, that the

probability of water accumulating in the instrument lines was

.

,

E decreased because the length of the lines was reduced by DCP-88-323 and periodic backflushing of the lines was deemed unnecessary.

,

During the second cycle, the positive offset was still present in i

the absence of dilution steam flow; however, licensee engineering j

personnel stated that the offset rapidly disappeared after the

.

introduction of dilution steam flow and did not inhibit the switch's

!

automatic isolation function.

This item is closed.

h.

(Closed) Unresolved Item (440/89002-03(ORP)):

Drywell head bolt l

torquing. As previously documented in Inspection Report

'

50-440/89002, dated April 6, 1989 Paragraph 9.b.(3), the licensee identified that the drywell head bolts had not maintained the installation torque value of 450-500 ft.lbs. At the close of that inspection effort, this item remained unresolved pending further review by the licensee.

.

A special safety inspection was performed by a NRC Region III specialist inspector as a followup to the licensee's investigation

>

into the root cause for the bolt relaxation.

The results of that special inspection _were documented in Inspection Report j

50-440/89014(DRS), dated July 6, 1989. As detailed in that report,

the licensee concluded that an inadequate preload value had been

'

specified by the original drywell head designer; however, the safety

significance was considered negligible (reference Licensee Event

,

Report (LER) 440/89-005-01).

The licensee's corrective action was l

to increase the bolting preload to two to three times the original value.

.

'

Based on the NRC staff's review of the licensee's investigation of root cause and corrective action, as documented in Inspection Report

'

!

50-440/89014(DRS), this item is closed.

• 1.

(Closed) Violation (440/89007-02a(DRP)):

Example of inadequate procedure. The subject item was one of three examples of inadequate procedures. The licensee responded to the violation in letter PY-CEI/NRR-1040L, dated July 21, 1989, in a timely manner.

The licensee identified the root cause of the inadequate procevure to be i.

a single deficiency in Of f-Normal Instruction (ONI)-R42-2, " Loss of i

DC Bus ED-1-B (Unit 1)," which failed to identify system response on a loss of power to a disconnect.

l l

l

l

,

_

e

.

.

.-

..

i _

'

w

c i

The corrective action taken by the licensee included a review of all g

DC load lists for completeness and accuracy. Temporary Change L "-

Notice (TCN) No. 2 was issued on May 9, 1989, to ONI R42-2 to

'

.

accurately reflect the plant response to a loss of power to the

,

specific DC bus disconnect that was found deficient.

In addition,

!

the Operations Manager issued a memorandum dated April 27, 1989, to s

all operations personnel emphasizing the licensee's policy of

" control not speed" during plant evolutions.

The inspectors considered the licensee's stated root cause for.the I

inadequate procedure to be correct and the corrective action taken to be appropriate.

Based on completion of the corrective actions as-stated above, this item is closed.

~

j.

(Closed) Unresolved Item (440/89007-04(DRP)):

Inadvertent actuation-

,

of containment isolation valves. This item was initially reviewed in Inspection Report 50-440/89007, dated June 22, 1989, Paragraph 8.b.(5).

At the time of that review the item remained unresolved pending receipt of additional information.

Licensee Event Report (LER)-89012 dated May 8,1989, stated the root cause for the inadvertent actuation of containment isolation valves was due to instructional deficiencies and personnel errors.

- i During a switching operation of an automatic bus transfer (ABT)

device from its emergency to its normal supply (during a plant refueling outage) a momentary loss of power to balance of plant (80P)

isolation relays resulted in an outboard BOP isolation.

Following that isolation, electrical power was being restored to three m

containment isolation valves when those three valves actuated closed.

The corrective action for the first 80p outboard " unexpected"

.

isolation was to revise the appropriate ABT transfer instruction (501-R10) to provide a caution on the possibility of receiving an isolation signal during the transfer operation.

The second isolation occurred when plant personnel failed to identify the effect of a tagout when a fuse removal caused a reset circuit to become inoperative.

Corrective action to prevent recurrence included j

counseling involved plant personnel on the performance of safety tagout review.

The inspectors considered the licensee's root cause identification to be correct and appropriate corrective action to have been taken.

Although the ABT transfer instruction was considered deficient, the

,

I inspectors concluded that the added caution was a procedural l

enhancement necessary during the unique plant conditions of a refuel L

outage.

Similarly, the second isolation occurred during unique plant j.

conditions with multiple tagouts involved.

This item is closed, k.

(Closed) Violation (440/89017-01(DRP)):

Failure to report within four hours the discovery of events required to be reportable in accordance with 10 CFR 50.72.

The licensee responded to the subject violation in letter PY-CEI/NRR-1062L, dated September 15, 1989, in a timely manner. That response stated that existing plant

i

_

.

.

'

>

... -

.

'

!

administrative procedures were adhered to when determining reporting l

requirements. However, after several discussions with the NRC staff

'

and receipt of the NRC. staff's expectations contained in Inspection

!

Report 50-440/89017, dated August _18, 1989, Paragraph 2.a., the

,

licensee acknowledged the need for timely communications.

,

!

As stated in the response to the violation, corrective actions included enhancement to the written guidance contained in Perry Administrative Procedure (PAP)-0606, " Condition Report and Immediate

'

Notification," to assist plant personnel when determining reportable events. Temporary Change No. 10, dated November 6, 1989, was issued

'

to PAP-0606 incorporating the NRC staff's expectations of event

reporting.

'

The inspectors noted that a specific root cause for the above violation was not identified.

The rules on reportability contained in 10 CFR.50.72 do not provide examples of every reportable event'

,

that a licensee may identify. As stated in the NRC staff's letter

'

accepting the licensee's response to the subject violation, dated October 13, 1989, the NRC expects licensees to err on the side of

reporting when there is doubt.. Based on the inspectors review of the licensee's completed corrective actions, this item is closed.

!

1.

(Closed)UnresolvedItem(440/89022-14(DRP)):

Pump test acceptance criteria. As detailed in Section 3.4.1 of the'NRC Diagnostic Evaluation Team (DET) report dated May 1989, the licensee had revised emergency service water pump test acceptance criteria in

,

a non-conservative manner.

This item remained unresolved pending the inspectors review of the licensee's basis and administrative

,

controls that were used to revise pump test acceptanca criteria.

'

During this report per od, the inspectors reviewed the licensee's administrative controls for revising pump test acceptance criteria.

Licensee letter PY-CEI/NRR-1063L, dated October 3,1989, submitted for NRC staff approval the Perry Inservice Test Program (ISTP) in accordance with the guidance of NRC Generic Letter (GL) 89-04.

-Interim approval of the licensee's ISTP was granted on January 2,

,

1990.

The current Perry ISTP was developed to meet the requirements l

of American Society of Mechanical Engineers (ASME) Boiler and

.

Pressure Vessel (B&PV) Code,Section XI, 1983 Edition, through Winter 1983 addenda.

The interim approved ISTP manual Paragraph 2.1.4 stated that ASME Code interpretation XI-1-79-19 was to be investigated if measured test quantities fell outside the allowable ranges specified in Section XI, Table IWP-3100-2,

" Allowable Ranges of Test Quantities."

)

The inspectors reviewed the changes made to emergency service water

>

(ESW) pump test acceptance criteria during the first operating

,

cycle.

In December 1986 and January 1987 Code interpretation XI-1-79-19 was implemented to expand the allowable ranges for ESW-B and ESW-A/C respectively. The changes to the allowable ranges were

>

-

.

9

-

i

,

-,

.;

.

-

.

..

implemented through procedural change requests to the surveillance

^

test instructions. As stated in the DET report, the licensee

,

expanded the allowable ranges by summing instrument inaccuracies.

'

.

That method increased the allowable ranges for ESW-A&B, 4 percent

'

and for ESW-C, 2 percent. The inspectors concluded, as had the DET, that the method of summing instrument inaccuracies was not supported

-

by engineering standards.

However, based on the inspectors review t

of pump performance data, the expanded allowable ranges were still

within the necessary ranges for the ESW pumps to fulfill their intended function.

Section XI, Paragraph IWP-3210 allowed the j

licensee to reduce the allowable ranges provided the pump could i

fulfill its function. That same paragraph required specifying in

>

the " record of test" the reduced ranges.

The inspectors asked cognizant licensee personnel if the method of

=,

summing instrument inaccuracies to. increase acceptance criteria (i.e. non-conservative) was employed at perry as an engineering standard on other fluid or electrical systems. The licensee stated

,

that the method of summing instrument inaccuracies to-increase i

acceptance criteria was not used elsewhere.

'

The inspectors reviewed the 11 cent.ee's record of tests " Pump / Valve I

Record of Corrective Actions " required by Section XI, Paragraph IWP-3210, for ESW-A dated July 30, 1988, and April 6, 1989. Those records appeared to meet the requirements of Section XI for documenting changes made to pump test criteria.

(July 1988, ESW-A reference values were reduced; April 1989, ESW-A reference values were increased following pump overhaul).

Those records in addition to the Technical Specification required reviews of changes to surveillance instructions appeared to be acceptable documentation of-changes made to pump test criteria allowed by Section XI including Code interpretation XI-1-79-19. However, the inspectors noted that the licensee's Independent Safety Engineering Group (ISEG) had issued interim Project Report 89-002A, " Emergency Service Water

,

SSFI," dated October 26, 1989. That report contained a number of

"

i unresolved issues, one of which (0 pen Item 21) concerned the s

i adequacy of documenting ESW pump reference value changes.

The

inspectors discussed the current status of resolving ISEG' concerns

"

contained in Project Report 89-002A with licensee management and concluded that adequate management attention was devoted to resolve those issues.

,

Based on the review performed as discussed above, this item is L

closed.

,

m.

(Closed)OpenItem(440/89022-19(DRP)):

Independent Safety

,

Engineering Group (ISEG) effectiveness. As detailed in

Section 3.5.8 of the NRC Diagnostic Evaluation Team (DET) report

.

,

t

. i x'

..

.

..

.

.

dated May 1989, the inspectors concluded that the ISEG had limited effectiveness due to a lack of adequate management attention and i

support.

The licensee response to this item stated that a revised ISEG charter was implemented to correct problems noted with

,

management support of ISEG.

This item was previously reviewad by l

the inspectors as documented in Inspection Report S0-440/90005, dated May.4, 1990, Paragraph 2.h.

At the conclusion of that inspection, this item remained open pending the inspectors review of ISEG effectiveness in accordance with the guidelines of NRC

Inspection Manual procedure 40500, " Evaluation of Licensee Self i

Assessment Capability."

During this report period, the inspectors reviewed the activities I

performed by the Perry ISEG since the DET report was issued in May 1989.

The review performed is documented below in Paragraph 3.

l Based on that review, the inspectors concluded that actions taken by a

the licensee-to improve ISEG effectiveness were adequately

!

1mplemented. This item is closed.

No violations or deviations were identified.

3.

Independent Safety Engineering Group (40500)

During this report period, the inspectors performed a review of activities performed by the licensee's Independent Safety Engineering Grodp (ISEG).

The objective of the review was to evaluate the-

'

effectiveness of the licensee's self assessment capability.

Since the NRC Diagnostic Evaluation Team (DET) report dated May 1989 identified the ISEG as being ineffective due to a lack of management attention and support'(ref. Open Item 440/89022-19), the inspectors review focused on

'

weaknesses previously identified.

a.

Background L

The requirement for an onsite ISEG to perform independent review of plant operations was applied to Perry initially (as a license I

applicant) in Three Mile Island (TMI) Action Item I.B.I.2.

The

staff concluded that the licensee ~ met the guidelines of TMI Action Item I.B.1.2 as documented in NUREG-0887, " Perry Safety Evaluation l

Report," dated May 1982.

Perry Technical Specification 6.2.3 l

detailed the function, composition, responsibilities, and required

-

records for the activities of the ISEG. The Ferry Nuclear Power y

Plant Quality Assurance Plan, Appendix B, " Independent Safety

,

Engineering Group Charter," Revision 2, dated November 6,1989, i

L:

detailed the licensee's implementation of the requirements of Technical Specification 6.2.3.

b.

Review of ISEG Organization i

Technical Specification 6.2.3.2 detailed the req tired composition of the ISEG. At the time of the inspectors revi u, five full time

!

members were assigned to ISEG, reporting to the ISEG chairman.

l The ISEG chairman was not considered a full time member since other l

3]

.

<...

C'

i

'

.

.

.

at management responsibilities were performed by that individual. The inspectors noted that the ISEG membership met the qualification requirements of Technical Specifications and included three members with post graduate degrees and five members registered as Professional Eng'eneers in the State of Ohio.

At the time of the in:.pectors review, the ISEG chairman reported to the Director, Perry Nuclear Engineering Department which met the requirement of Technical Specifications. However, during the report period, the licensee stated that in response to recent organizational changes the ISEG may (in the near future) report to the Vice President - Nuclear. The inspectors noted that the Vice President -

Nuclear was located onsite and were-the ISEG to report to that level of management, no reduction in the ISEG effectiveness would be anticipated. The inspectors concluded.that the current and future planned reporting level for the ISEC was sufficiently senior in the licensee's organization to effect corrective action recommendations, c.

Review of ISEG Investigation Reports The inspectors reviewed the following ISEG investigative reports issued since M.y 1989:

ISEG Report-Date Subject

.89-002A(interim)-

10/26/89 ESW SSFI 89-003 11/17/89 RHR Waterhammer 89-004 9/ 7/89 Rosemont Syndrome 89-005 1/16/90 Loss of Ventilation 89-006 4/ 9/90 RHR Heat Exchanger 89-007 2/ 7/90 Control Room Ventilation 89-008 6/23/90 Suppression Pool Volume 89-009 2/ 6/90 Drywell Head Bolts89-010 5/25/90 Offgas Air Handling 90-002-4/ 4/90 OER Program Special Evaluation 2/ 1/90 RCIC Modification Special Evaluation 4/ 2/90 Scram Pilot Valve-Failures The inspectors review of the above reports indicated that the topics selected for investigation by the ISEG were appropriate based on the licensee's operating history since May 1989.

Identified problems with Rosemont transmitters, Residual Heat Removal (RHR) waterhammer events, and RHR heat exchanger degradation were all current industry issues. The plant specific reports on drywell head bolts, offgas air handling unit, Operational Experience Review (0ER) program effectiveness, Reactor Core Isolation Cooling (RCIC) modification, and scram pilot valve failures were issues identified in Licensee Event Reports (LERs), enforcement history, and operating history where weaknesses had been previously identified. The inspectors

..

.

-

..

.

@

found the above ISEG reports to be thorough and recominendations valid.

In addition, the inspectors noted that unscheduled reviews, identified above as "Special Evaluations," were performed appropriately on a RCIC modification (required urgent Technical Specification Review) and scram pilot valve failures (subject of escalatedenforcement).

<

d.

Review of ISEG Recommendations

,

The inspectors review of ISEG recommendations inciuded both Open and Closed issues.

In addition, during the review of ISEG reports, the

,

inspectors noted several ISEG " suggestions," "open issues," and

" unresolved issues." As suggested, open and unresolved issues

-

appeared during the ISEG investigations and were tracked to resolution by the ISEG., " Suggestions" that appeared in ISEG reports were not binding requirements and were offered for the primary report recipient's consideration with no followup.

Formal " recommendations" were transmitted with the approved ISEG report to the responsible Perry organization.

ISEG recommendations were further broken down into Major or Minor priority. All Major'

recommendations required a written response from the responsible manager if that recommendation was not to be implemented. The inspectors reviewed two recommendations (89-004-1/2) that had been rejected'by the responsible manager and found adequate justification was provided.

At the time the NRC DET report was issued in May 1989, fifty-one

<

ISEG recommendations were open and fifty of those had been open over 90 days.

In addition, the average closure time for ISEG recommendations was about 18 months.

The inspectors noted during the current review of ISEG recommendations that twenty-three were-open and fifteen of those were open over 90 days. The average age of open ISEG rs;ommendations was about 8 months.

The inspectors concluded that ISEG recommendations were tracked to resolution.

The inspectors review of the ISEG recon =cndation backlog indicated that priorities had been established with appropriate due dates, e.

Review of ISEG Records Technical Specification 6.2.3.4 required that monthly records of activities per formed by the ISEG be prepared and forwarded to the Director, Nuclear Engineering Department each calendar month. The inspectors reviewed ISEG performance analysis reports for the months of February, March, April, i May 1990. Those reports summarized ISEG activities during the p eceding month and included status on current ISEG investigation reports; results of ISEG surveillance activities; summary of significant condition reports; and the status of ISEG open recommendations.

The inspectors concluded that the reports reviewed met the requirements of the Technical Specifications.

lY

,,

AA

..m.....

..........

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

-

.

.

.

A f.

Inspector Evaluation

_

~

Based on the review of the current ISEG organization; review of ISEG investigative reports; review of ISEG recommendations including validity, age, and tracking; and review of ISEG records, the inspectors concluded that the licensee's ISEG was effectively implementing the requirements of Technical Specifications.

No violations or deviations were identified, h!

4.

NRC Information Notice Followup (92701)

During the report period, the inspectors performed a review of licensee actions related to the below Information Notice issued by the Office of

<

Nuclear Reactor Regulation.

The review included verification that the information notice was reviewed for applicability; the information notice T

received proper distribution to appropriate personnel-and if applicable,

]]

the scheduling of appropriate corrective action was completed.

-

i a.

(Closed) Information Notice 88-24 (440/88024-IN):

Failure of air

~-

operated valves affecting safety related equipment.

This item was previously reviewed by the inspectors as documented in Inspection Report 50-440/90005, dated May 4, 1990, paragraph 5.a.

At the completion of that review, this item remained open pending the

~

inspectors review of additional licensee followup to the subject

._

information notice.

During this report period, the inspectors reviewed licensee memorandum for Technical Assignment File (TAF) 80351, dated May 16, 1990. That memorandum documente1 the licensee's review of all Automat;c Switch Company (ASCO) solenoid valves that had lower

" maximum operating pressure dif ferential (MOPD)" than what could be postulated on an air system pressure regulate-failure.

The licensee concluded that the concerns identified in the subject notice were not applicable at Perry.

'

The inspectors noted that the licensee had performed an adequate

review of the subject notice and the conclusion that the concerns

therein were not applicable to Perry was reasonable. Thi s T. 'm i s closed.

No violations or deviations were identified.

5.

Licenspo Event Report Followup (92700)

Through direct observations, discussions with licensee personnel, and d

review of records, the following event report was reviewed to determine

if repcrtability reouirements were fulfilled, immediate corrective actions were accomplished in accordance with Technical Specifications

'

and corrective action to prevent recurre 'ce had been accomplished.

-

..

.

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

~

~ - - ' - - - -

-

'

,

.

.

(Closed) LER 89029-00:

Deenergized alternate sampling equipment results in failure to meet required surveillance.

In November 1989, plant personnel deenergized a temporary gaseous effluent sampling device that had been installed to meet the requirements of the Technical Specificatio.s.

-

With the permanent heater bay / turbine building vent radiation monitor removed from service, Technical Specification Table 3.3.7.10-1,

=

Action 122, required that continuous sampling be performed with auxiliary

.

equipment.

As stated in the event report, plant technicians removed the temporary sampling pump from service without recognizing that action violated plant Technical Specifications.

Initially, the licensee did not consider the

~

loss of the alternate sampling equipment to be significant or reportable; however, the licensee acknowledged the reportability requirement af ter discussions with the inspectors. The inspectors noted that the momentary

?oss (10 minutes) of the sampling equipment had little safety significance. The inspector., were concerned during initial review of

event occurrence, that the administrative controls in place allowed plant h_

Mrsonnel to defeat required surveillance equipment.

The licensee identified the root cause of this event to be a procedural deficiency and a contributing personnel error.

The procedural deficiency F

was corrected by enhancement to the applicable chemistry instruction

"

(CHI-42) to improve labeling on temporary sampling equipment.

The

_

personnel error was addressed by counseling plant technicians directly involved in removing test equipment frorr service without consent of the

_

control room operators.

In addition, Instrument and Control.(l&C) and E

Chemistry Technicians were provided training on the event occurrence.

The inspectors concluded tnat the licensee's root cause determination was correct and appropriate corrective actions had been completed.

Failure of the licensee to continuously sample the heater bay / turbine ouilding gaseous effluent exhaust in accordance with Technical Specification

-

iable 3.3.7.10-1, Action 122, was a non-cited violation 4t.

-

-

(NCV 446/90008-01(DRP)).

The 'icensee-identified violation is not t>eing g@,

,'

_

cited because the criteria specified in Section V.G. of the Enforcement Policy were satisfied in that:

the violation was identified by the

-

"

licensee; the violation would normally be classified es a Severity

'

-

Level IV or V; the violation was reported in accordance with E

10 CFR 50.73; the violation was corrected in a reasonable time frame including measures to prevent recurrence as discussed above; and the violation was not willful nor one that should have been prevented <due

-

-

to licensee corrective actions to previous violations.

This item is

,

closed.

No deviations were identified, however one non-cited vichtion was identified.

r E

E i

l

-

-

u-

..

..

..

...

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

-

...... i, ---,

- - - - - - - -, - - - - - - - - - - ' - - - -

p,

-

<

,

s

-

.

i m.,

,

..:

,

i 6..

Safety Fval'uation Report Followup I'nspection Items (92701)

'

'As~previously documented in Inspection Reports 50-440/85022, 50-441/85012, and 50-440/85033, certain Three Mile Island (TMI) action

-

. items were inspected by Region III: inspectors to confirm licensee implementation. The below listed TMI action items were not included in

"-

the initial Region III review and were reviewed during this report period to document the. basis for initial exclusion.

_(Closed) TMI action item II.E.4.1.2 and II,E.4.1.3:

Dedicated hydrogen penetrations. As documented in Perry Safety Evaluation _ Report,

-

NUREG-0887,; dated May 1982, paragraph 6.2.7(2), the Perry design T

. incorporated the un of hydrogen recombiners located inside containment.

Therefore, the NRC staff position on dedicated hydrogen penetrations in-if

TMI item II.E.4.1 was_not applicable to Perry.

These items are closed.

'

No violations or deviations were identified.

,

i

!

.7.

Monthly Surveillance Observation (61726)

_

For the below listed-surveillance activities the inspectors verified one

=

or more.of the following:

testing was performed _in accordance with

. procedures; testsinstrumentation was calibrated; limiting conditions for-operation.were ' met;, removal and : restoration of the affected components were properly-accomplished; test results conformed with technical specifications'and procedure requirements and_were reviewed by personnel other:than the individual directing the test;;and that,any deficiencies identified-during. the testing were properly. reviewed and resolved by appropriate management' personnel.

=

~

-Surveillance Test No.

Activity SVI-P45R-T2002,-Revision 6

" Emergency Service Water (ESW)

Pump-B and Valve Operability At Test" SVI-821-T0076B, Revision 2

" Main Stea_m-Line Low Condenser

Vacuum Channel B Functional for 1821-N675B" SVI-C11-1006, Revision 3

" Control Rod Maximum Scram

,

. Insertion Time" Details

,

_.

(;

a.

On April 23, 1990, the aactor operator.who was the lead performer T

of Surveillance Instruction (SVI)-P450-T2002, " Emergency Service

'

Water-(ESW) Pump B and Valve Operability Test," Revision 6, incorrectly documented in step 4.5 that the'ESW system was not in the-winter mode when it was. The SVI was written to be performed with a

.

.,

=m

-

-

(

-e

)

"

,j y

,

-t

,

,&

-.- - - -_

_ __-_

._

%

"

,

,

l M.

c.

\\

'

h;,

..:

e

.

.

[C i's the ESW; system'inLthe summer mode. -In su p 5.1.2.7.a, the ESW pump.

"B" flowrate was calculated to be-8,660 galloos per minute (gpm)

which was below the:SVI's. stated limit of 8,667'gpm and-therefore in s

L the required action range. The lead performer then incorrectly-

initialed step 5.3.1. which indicated that the ESW pump "B" flowrate was in either the acceptable or alert ranges. The lead performer

,

signed the SVIt as completed and acceptable and failed to notify. the unit supervisor-(al senior reactor operator) of the failed SVI. The-n unit supervisor reviewed the SVI and signed it as acceptable.,.'He failed to ider+ ^ the flowrate as being below 8667 gpm, failed;to declare the "

..,p "B" inoperable, and failed to notify the shift

' supervisor-as n auired by step 3.3 of Perry Administrative Procedure (PAP)-0205, Revision 6, " Operability of Plant Systems."

_

- On April US,1990, while performing the Inservice Inspection review as required by PAP-1101, " Inservice Testing of Pumps and Valves,":

'

the system engineer identified that ESW pump "B" had failed the SVI

'due to inadequate system flow. At 3:15 p.m., on April-25, a.second performance of the SVI determined ESW. pump "B" flowrate to be 8,500-gpm. ~~The unit supervisor properly declared inoperable:. ESW pump

"B", Division 2 diesel generator,-low pressure coolant injection B/C,.

containment spray-B,-suppression pool cooling-B, control room emergency ventilation-B, combustible gas mixing compressor-B,

'

ic containment hydrogen analyzer-B, emergency closed cooling-B,' and shutdowncooling-B.'At4:00p.m.onApril-25theoperationsmanager

'"

changed the beginning of inoperability of ESW loop !B" to 11100 p.m.,

April 23, 1990,. when'the on-duty unit supervisor should havetrealized w

i that the SVI had' failed. After the second perforcanceLof-the SVI, it

was noted-.that the_ test gage installed to measure-ESW pump "B" discharge-pressure for the SVI. indicated 1.36 psi below'zero even-af ter it was removed from the system;1.therefore, the shift supervisor.

. believed that tne SVI. data might.be in error and ordered that a calibrated pressure gage be installed and the SVI be performed a third time.

. Technical Specification 3.8.1.1., action b., required-that Division 1

. "

and.3 emergency diesel generators (EDG) be demonstrated operable by testing within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of Division 2 EDG inoperability; however,.

the licensee failed to' meet this requirement because the inoperability time period of Division 2 EDGlhad also been revised z to 11:00 p.m., April 23. 'The shift supervisor decided to:

run Division 3 EDG, reperform the SVI and if the SVI failed then run Division 1 EDG..The third performance of the SVI was completed at 11:55 p.m.,' April 25, and indicated that ESW pump "B" was operable, e'

The shift supervisor concluded that the-ESW pump had been operable

'

at all times during the previous two days and there had not actually been any actions required by technical specifications. Therefore,

,

$

l I

?

'

ih l

,

,..,

.

,m

,,,,

I

\\

m

e

-

-

T

..,

,#

.

g.:

licensee personnel did not run the Division 1 EDG and concluded

.

.

that no Actio'n requirements of Technical. Specifications had been d

'

' violated.. These conclusions appeared reasonable,

,,

The above examples of failure to follow procedures were a non-cited i

violation (NCV 440/90008-02(DRP)) of Technical Specification;6.8.1.a.

!

The. licensee-identified violation is not being cited because the-

,

criteria specified in Section V.G ofLthe Enforcement Policy were

satisfied in that:

the violation was identified by the licensee; this specific violation would normally be classified at s Severity.

Level IV or V; the violation did not have to be reported to'the NRC;

'

the violation was'promptly corrected by licensee personnel when they.

became aware of it; and it was not a willful violation.

'

a b.

On1May 8, 1990,.the inspector observed.the perform)nce of-

surveillance instruction (SVI)-B21-T0076B, Revisiot 2. " Main Steam'

i Line Low Condenser Vacuum Channel B Functional for 1821-N675B".

-

,

b c.

On May 19,.1990, the inspector observed control room activities'

$

y performed as required by step 5.1 of SVI-C11-1006, Revision 3,

.

,

" Control Rod Maximum Scram. Insertion Time." After each of the 23

.,

. control rods. tested were' individually' scrammed, the: reactor engineer

'

l checked the scram times that were displayed on an unofficial CRT

~

screen in -the control room against the limits of Technical D

Specification 3.1.3.2.. and then notified the control room reactor

,

operator and the unit' supervisor that-the scram time-was acceptable.

J f

l After the reactor engineer had notified.the unit supervisor and shift supervisor OVat-the control rod scram time. testing was U

T complete and satisfactory, the reactor engineer. reviewed the i

emergency response information' system-(ERIS) computer printout

'

.

rentitled " Core : Cycle updated scram timing information"-(the quality

'

,

,

Erecord-of test results) and found it. indicated control rod-30-15 had j

not. met the requirements of the TechnicalLSpecification.. When informed of thc.' discrepancy, the-unit supervisor declared. control rod-30-15 inoperable, had it fully inserted,'and hydraulically Ldisarmed as=' required by the Technical Specifications.. Reactor engineering-personnel retested'the rod with-an independent Dranetz

'

,

time events analyzer.

The Dranetz analyzer, the unofficial _CRT

. display.and the official computer printout indicated that-control i

rod 30-15 met-the requirements of Technical Specifications-and it

~

was declared operable.. Computer engineering personnel were seeking

'

,

to determine _the. exact roet cause of the'ERIS computer's discrepant printout for control rod 3u-15 indication on May 19-(preliminar11y,.

it was; believed to be a specific software problem); and.to insure

_

that the. program for the-official computer printout was properly.

analyzing data.. Licensee personnel wrote condition report 90-118 -

to document their root cause and corrective action analyses.

'

No deviations were identified, however one non-cited violation was

. identified.

'

-

,

(

m

,____.________-___._.------m----

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

^

o

,.,

n

+

..

,

.

8.

Monthly Maintenance Observation (62703)

,

Station maintenance activities of' safety related systems and components-listed below were observed / reviewed to ascertain that they were conducted-4 accordance with approved procedures, regulatory guides and industry.

codes or standards and in conformance with technical specifications.

'O Th'e following items were considered during thic. review: the limiting.

conditions for operation were-met while-components or systems-were removed _from service;= approvals were obtained prior'to initiating the work; activities were accomplished using approved procedures and were-inspected as applicable;. functional testing and/or calibrations were

-

,

perforr.ed-prior to' returning components or systems;to-service; quality.

control records were maintained; activities were. accomplished by qualified personnel; parts and materials used were properly certified;

.

radiological controls were implemented;=and, fire prevention: controls were implemented.

Work ~ requests were. reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety related equipment-maintenance'which may affect system performance.

The following specific maintenance activities were observed / reviewed:

Details

a.

Work ' Order (WO) 89-6224, Revision 1, which flushed'and cleaned the upper bearing:1.ubricating oil reservoir for ESW pump "A" because

-

a sample indicated :that the particulate: concentration was too high.

The W0 also reduced the pump's-packing leak-rrte-to within the acceptable range.

b.

WO-90-1618, the work' request was written because operating =per.sonnel found the submersible plant discharge dechlorination' sample pump, OP84-C001B, with all three mainline fuses blown and its: thermal.

overloads tripped. The WO replaced the pump and-a feed cable. The.

functional-test was satisfactory.

c.

WO 90-1838, which. removed and. filtered the fuel oil from the yard

'

storage tank for the Unit 1, Division 1, emergency diesel generator.

The work order also cleaned the tank and ret 4rned the oil to it.

d.

.WO 90-2134, which cleaned and inspected the fuel oil yard storage tank for the Unit 2, Division 2, emergency diesel generator.

No violations or deviations were identif-ied,

,,

t 1;

-

2

',

_ _ _ _ _ _

_ _ _ _ _ _

_ _ _ _. _.. _

')

-- t

, ll

,%

<

9 '.,

Operational Safety Verification (71707)

y a.

General The inspectors. observed control room operations, reviewed applicable logs, and conducted discussions with control-room operators during-e this inspection period. The inspectors verified the operability of-f selected emergency systems, reviewed tagout records and' verified tracking of Limiting Conditions-for Operation associated with

-

'

affected components. Tours of the intermediate, auxiliary, reactor, and turbine buildings were conducted to observe plant equipment-conditions including potential: tire hazards,. fluid leaks, and'

excessive vibrations, and to verify that maintenance requests had been initiated for certain pieces of equipment in need of

. maintenance.

The'. inspectors by observation and direct interview.

verified that the physical security plan was being implemented in accordance with_-the station security plan.

A

\\

The inspectors observed plant housekeeping / cleanliness conditions-and verified implementation of radiation protection controls.

These reviews and observations were conducted to verify that

. facility operations were in conformance with the requirements b

established under the Technical Specifications,10 CFR, and administrative, procedures, b.

Details Technical Specification 3.6.3.1.a required that the suppression. pool volume be maintained between 115,612 and 118,548 cubic feet which-

' was equivalent to maintaining the suppression pool level between.18-and:18.5 feet respectively.

On May 11, 1990, licensee-engineering; personnel: determined, as documented in licensee Condition Report 90-113,: that the relevant desi levels of-the portions of the' gn calculation. assumed:-that"the suppression pool-in the drywell and in the containment would be.the same and that there.would be no q

difference in the air pressures infthe drywell and the containment.

h Technical Specification 3.6.2.5 allowed the' drywell pressure to 'be -

as much as 2 psid higher than the containment pressure. -Both specifications were applicable during operational conditions 1, 2, and 3.

If the suppression pool level was at 1'0" with 0 psid-drywell-to-containment differential pressure (dp) and the.dp

-

N

. increased to the allowed 2 psid, the drywell suppression pocl level would have dropped below 18' and the containment suppression pool'

+

_ level would have raised to about 18' 4-1/2".

Suppression pool level'

sensors _ measured -the level of' the pool in the concinment; therefore, control room operators would have been allowed by the Technical Specifications to pump the suppression pool down until

.18'0" level was indicated. The resulting shortfall in suppression pool volume would have been about 2200 cubic feet below the minimum value required by the' Technical Specifications. The licensee wrote

-1

,

<,

--

p

,

w

,.g (

f

['.

'

^

j

..

_,

.S.

'

,

.

...

.

'

a daily instruction to all' control room operations personnel which l

e required them to maintain-the indicated suppression pool level compensated-for-drywell-to-containment dp in accordance with an

engineering. calculation.

The licensee changed its Technical Specification required plant rounds' instruction (PRI-TSR), to

require that indicated suppression pool level was corrected to i

compensate for drywell-to-containment dp variation-thus insuring that the minimum suppression pool volume required by the Technical

Specifications was maintained, j

No violations or deviations were identified.

L<

10.

ReviewofPlantModifications(37828)

.

>

J At the March 15, 1990, meeting of the Plant Operations Review Committee-

.(PORC), Design Change Package.(DCP)-89-182, Revision 0, which proposed the vertical extension by four feet of the separator storage pool wall:

.

to provide radiation shielding of the steam separator during refueling fl

,

outages, was tabled.

The'PORC recommended improvement in the: documentation

,

l of the DCP's technical basis (for example the.PORC pointed out that the

'

calculation failed to deduct from the suppression pool makeup <(SPMU)

l L

capability the volume that was to be displaced by the wall extension L

itself).

The DCP was withdrawn from consideration with no discussion at l!

the PORC meeting held on March 29, 1990,:which the inspectors attended.

• D In-the March 29 revision of.the proposed.DCP, Safety Evaluation 90-48 stated thaticalculation G43-6 showed that the wall extension would not

affect the ability of:the-SPMU system-to. perform its safety function.

On H

April 30, 1990,'the inspectors found'that. draft calculation G43-6 used i

j~.

nominal upper pool design dimensions to calculate SPMU volume available

<

'

xand did not use as-built pool: dimensions. Also, these calculations'did

not account for any volume-reduction;due to negative variation of L

dimensions within the allowed construction tolerances.

,

'

A'pr.evious violation'.(440/85081-3a(DRS)) (paragraph 4.b, page 7) was issued partly because dimensions'used.to calculate suppression pool level

,

J

. change from. upper containment pool level change were nominal' design-dimensions and not as-built dimensions. One of the licensee's corrective m

actions:for:that violation was the dimensional tolerance calculation,

-

l reference 2 of Field Change Request (FCR)-01360, which was' referred to in the closeout of the violation in : Inspection Report 440/86006, paragraph 2.1. _ This:cah

' ion determined the " worst case" upper pool o

,

volume dumped'to the up lon' pool. On May 1 the inspectors met with a licensing engineer ano a m aanical design engineer.

After recognizing

'

~

the inspector's concerns 9e mechanical design engineer calculated, in q

File Code (FC) 3:25.9, R

.sion 0, the upper pool volumes available for suppression pool makeup (SPMU) using primarily as-built upper pool

~

t dimensions taken directly from the Newport News Industrial Corporation

.

surveyo'r's field books. After reviewing that' calculation, the inspectors L

'noted that the calculation did not deduct the volume occupied by the-

!,

,

.

,

e

'.

b

..

.

>

_. _.....

...

.

.

..

.;

.

,

a:

,

I L

~

-f portion of some' piping 'and the drywell head above elevation 680', both of which had been deducted in calculation G43A, Revision 2.

When contacted, the mechanical design engineer revised the~ calculation and; included those-volume deductions in-Revision 1 of calculation FC 3:25.9.

The inspectors:

.had no further concerns with the calculation of the upper pool. volume.

'

No violations or deviations were identified.

.11.

Onsite Followup of Events at Operating Power Reactors (93702)

..

a..

General-The' inspectors performed onsite followup activities for events which-r

occurred during the inspection' period.

Followup; inspection included.

one or more of the following:

reviewr of operating-logs, procedures,

_

m; condition reports; direct observation of licensee actions; and-interviews'of licensee personnel.

For each event,1the intoectors>

reviewed one or more of the following:

the-sequence offactions;.ther

.

' functioning of safety systems required by plant conditions; licensee actions to verify: consistency with plant procedures and license conditions;~and verification of the nature-of the event.

Additionally, in some cases,0the inspectors verified that licensee investigation had identified-root causes of equipment malfunctions and/or personnel. errors and were taking or had taken appropriate corrective actions. Details of the events and. licensee corrective actions noted during the inspectors' followup are provided in Paragraph b. below.-

.

.b.;

Details

_(1)' Loss of Control Room Emergency Ventilation System On April 16, 1990, at about-11:06 p.m.-(EDT), while operating.-

-

at 100 percent power,'a loss of safety function occurred when

,

train "B" of the control, room emergency ventilation system was declared. inoperable after a control room: operator discovered,.

~

during a panel walkdown,: that its supply fan was not operating.

and'it could not be started. The "A" train had been previously declared inoperable because personnel were taking' a. routine charcoal' sample..The shift supervisor took action within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to commence an orderly plant shutdown in accordance with Technical Specification 3.0.3.

In addition, the shift supervisor directed that a priority work request be initiated to troubleshoot failure of the "B" control room ventilation train and that sampling be completed on the "A" train so that it could be restored to operable. status. The licensee initiated Condition Report (CR) 90-90 to document their inbornc1 investigation of the event.

,

..

..

s'

i

---.

........

-

sa

-

.g R

V.*

.v.

LAt ~about 3:21' a.m.: on April 17, the licensee restored; train "B"

~

.

~ of' the. control ' room ventilation system to service and exited-Technical Specification 3.0.3.

At-about 3:53 a.m. on, April 17,-

sampling was completed on the "A"< train and it wa: returned to

<F operable status.

The? licensee informed the NRC operations center of.-this event-at about.11:44 p.m. on April 16-within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> " requirement of 10-CFR 50.72(b)(2).

The. inspectors-will review the final.

root cause determination and the licensee's corrective actions; to prevent recurrence after issuance = of.the required licensee -

event' report.

.(2) Loss of Primary Containment Integrity 18,- 1990,c t about 1:07 a.m. (EDT), while operating at On April a

100' percent; power,' the licensee experienced a loss of primary.

Ve containment safety function for approximately 2 minutes when the inner door. of the upper containment airlock was opened while there:was'~about a one inch tear in the seal of the outer-door. The. licensee, believed-that the outer door's seal ruptured when the-inner door was opened.

The shift supervisor took: action.within 'I hour' to commence an' orderly plant -shutdown-in accordance-with Technical Specification 3.0.3.

Licensee personnel locked the operable inner door closed as required by

technical specifications and repaired the outer. door seal. The=

licensee initiated CR 90-93 to document their internal Linvestigation of'the event, The-licensee informed the NRC operations center-of this event

'atiabout 4:44 a.m;, on April 18,-within-the-4 hour requirement

,

of.10 CFR 50.72 (b)(2).

The' inspectors' will review tha final

,

root cause determination and the licensee's corrective actions'

to prevent-recurrence after issuance of the reouired licensee E

event report.

(3): Reactor Water Cleanup (RWCV) System Inboard Isolation

-,

On April 20, 1990, at about 1:25 p.m. (EDT), with the reactor operating.at 100 percent power,.the licensee experienced a Reactor Water Cleanup (RWCV)- system inboard ~ isolation upon a Division II high differential flow signal-for greater than 45 seconds. Operators verified that the isolation valves were

.

-closed and that there was no actual loss of reactor water. The unit supervisor initiated a priority work order to the-instrumentation and control personnel to determine the cause of

,

the' isolation.

The licensee initiated CR 90-95 to document its

internal' investigation of this event.

L

,

'

.6

.

_

_ _ _ _ _ =. =.........

.

. - - - - - - - -

x.

[\\,v,[;;.;;(

'

,

l(

$

s o

P

~

'

' The licensee' informed the~ NRC operations-center of this event

-

J at about 3:23 p.ma on April 20 within the 4-hour requirement of:

10CFR50.72(b)(2). - The: inspectors-will review.the' final ~ root cause determination:and the 1icensee's corrective actions to-

-

prevent recurrence af ter issuance of the required ' licensee

'

event report.

.

,,

(4) Loss of Containment Spray and Suppression Pool Cooling On_May 17,-1990, at about 7:30 p.m. (EDT), with the plant operating at 100 percent power, a-loss of. containment spray and r

suppression pool cooling safety functicns' occurred for about 15 minutes when sufficient flow through the "B" train residual-heat removal (RHR) heat exchangers could-not be obtained and

,

the-"A"1RHR pump' breaker was racked out for. surveillance-testing.-

Technical Specification 3.6.3.3.,= action b. required i.

_that with.both suppression pool cooling loops inoperable the'

i'V plant must be placed in at least HOT SHUTOOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.,

!

~0perations personnel found that'the bypass valve for the "B"

.

'RHR heat exchangers could not.be shut because the nut

connecting the operator to~its stem was stripped.

Priority WorkOrder(WO) 90-2544 was written to repair the RHR "B'! heat

-

-exchanger's bypass valve..The licensee initiated CR 90-117 to document their' internal investigation of the event.

'

At about 7:45 p.m. on May 15 the-licensee restored train "A" of the RHR-system by' racking in the "A" RHR pump breaker and

, exited the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shutdown action statement.

_.

_

The licensee informed the NRC operations center of this event at about 10:42 p.m. on May 17 within the 4. hour requirement of

-

'10 CFR 50.72(b)(2). The inspectors will review the final root'

cause determination and.the licensee's corrective actions to prevent recurrence after issuance'of'the required licensee'

= event report'.

'

(5) Spurious Engineered Safety Feature Signals

"

On May 31, 1990, at about 2:50 a.m. (EDT), with.the plant operating at 100 percent power, trains "A" and "B" of the control room ventilation system received spurious _ signals' to

"

automatically initiate into their. emergency modes. Train'"A"

-

was already running in its emergency mode.and train "B" was'

_

removed from' service. The spurious signals resulted because

4 the. restoration steps to put the "B" train'back in service did

>

not reset the chlorine monitors _before power was restored to 7,,

them. The licensee informed the NRC operations center in

-

accordance with 10 CFR'50.72(b)(2) that an unplanned engineered safety feature actuation had occurred. The licensee initiated 9-CR 90-130-to' document their internal investigation of the i

event.

==,

i-Df

s

,

>

p

\\.

)

___..

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

.

.

':e,

a,

.

..

The licensee later concluded.that the spurious signals to the J

- A".and "B" trains were not reportable because: :1. ) the "A"

"

-

train had already been placed in the emergency mode as part off a planned evolution and 2.)- both fans of-the "B"' train were secured and'never st4rted whi.le only a damper of the "B" train

-

closed. Question.6.9 of supplement 1 to NUREG'1022 stated that

.if the system was not required-to be operable'and it was properly removed from service such that it--could not perform itsiintended function, then a spurious actuation of part of the system was not reportable.

The inspectors found the licensee's conclusion to be reasonable.

3, No violations or~ deviations were identified.

.

12.

Evaluation of Licensee Self-Assessment Capability (40500)-

"" '

The Plant Operations Review Committee (PORC) was the licensee's onsite review committee. The inspectors reviewed the below listed PORC meeting-minutes published during the inspection period and determined that:

the minutes were thoroughly documented; the minutes clearly denoted.

the topics discussed and the basis for any conclusions; the action items were clearly identified and followed up;.and the committee reviewed" safety-significant concerns that were not specifically required by-O technical specifications.

PORC Meeting No.

Dated 90-034 4/26/90

'

.90-035 4/27/90 90-040 5/10/90_

90-041 5/11/90 90-042 5/17/90 90-043 5/24/90 No violations or deviations were identified.

13.

Plant-Status Meeting (30702)-

.

NRC Management met with CEI management on April-17,1990, at tue Perry Lplant, in order to discuss.the current status'of monthly performance

' indicators, of fgas system corrective ' actions; and the April 3 ALERT.

Personnel-in attendance at.that meeting-are designated by (#)-in paragraph 1 of this report.

The licensee discussed the April 3 ALERT and actions taken to assure adequate review of' systems or components removed from service. A discussion on the licensee's continuing efforts to improve offgas' system

,

. performance was conducted by the cognizant engineering organization.

In

= addition, the licensee reviewed Technical Specification change requests

,

that had been submitted for NRC staff review and approval prior to the refuel.ing outage scheduled to start in September.

.... _ _ _ _ _

. _ _. _. _ _ _ _ _.. _. _....

.

..

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

e c

x s'

'

c.

t.'

aj

>

NRC-manage'aent: acknowledged' the. licensee's plans' and current plant -

status.

14.

Violatious For Which A " Notice'of Violation" Will Not Be Issued Th'e NRC.uses the Notice of Violation as a. standard method-for formalizing

-

the existence of a violation;of:a legally binding requirement. However, because the NRC wants to' encourage and support licensee's. initiatives; for self-identification and correction _ of problems, the NRC will-~not -

<

generally. issue a Notice of Violation for a violaticn that meets the tests of 10 CFR 2, Appendix C,LSection V.G.

These tests are:

1)-the violation was_ identified by the licensee; 2) the viciation'would be :

categorized as Severity Level'IV or V; 3) the violation was reported to -

the NRC,-if_' required;; 4)- the violation will be corrected, including-measures to preventirecurrence', within a reasonable -time period;' and 5)'

"

it was.not at violation that could. reasonably be expected to have been-

'

prevented _ by the-licensee's-corrective action for a previous violation.

Violations of regulatory requirements-identified-during thel inspection L

period.for which a Notice of Violation will not be issued were discussed-in Paragraphs-5. and 7.a.

15.

Exit' Interviews -(30703)

The inspectors met with,.e licensee representatives denoted in Paragraph 1.throughout the inspection period and on June 11, 1990. The inspector summarized the scope and results of the inspection and discussed the-

-likelyl content of the' inspection report. The licensee did not indicate that any.of the information disclosed during-the inspection 1could be'

-considered ~ proprietary in nature.

'During the:-report period, the inspectors attended the following exit interview:

<

Inspector Exit Date M. Kopp April 26, 1990 t

$

r3

&

s

)

l

'

.-- _--- _ -

-