ML20202J130

Insp Rept 50-440/97-16 on 971004-1201.Violations Noted. Major Areas Inspected:Operations,Maint & Plant Support

ML20202J130
Person / Time
Site:	Perry
Issue date:	01/02/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20202J114	List: IR 07100004/2012001 ML20202J107 ML20202J130
References
50-440-97-16, NUDOCS 9802230089
Download: ML20202J130 (21)

See also: IR 05000440/1997016

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION ll1

Docket No: 50-440

License No: NPF 58

Report No: 50-440/97016(DRP)

Licensee: Centerior Service Company

Facility: Perry Nuclear Power Plant

Location: P. O. Box 97, A200

Perry, OH 44081

Dates: October 4 to December 1,1997

Inspectors: D. Kosloff, Senior Resident inspector

J. Clark, Resident inspector

G. Harris, Senior Resident inspector, Fermi

K. Stoedter, Resident inspector, Clinton

Approved by: Thomas J. Kozak, Chief

Reactor Projects Branch 4

9802230099 980102

PDR

0 ADOCK 05000440

PDR

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EXECUTIVE SUMMARY

Perry Nuclear Power Plant

NRC Inspection Report No. 50-440/97016(DRP)

This inspection included a review of aspects of the licensee's operations, maintenance,

engineering, and plant support functional areas. The report covers an 8-week period of

resident inspection. One violation of NRC requirements was identified.

Operations

. Thorough preparations were made prior to retuming the unit to power following

refueling outage 6. The startup was well controlled and accomplished without error.

Shift tumovers and briefings were generally thorough and clear (Section O1.1).

The licensee identified that an operator's failure to ensure the reactor water cleanup

(RWCU) leak detection bypass switch was in the bypass position during the

performance ofloss of offsite power testing caused an inadvertent ieolation of the

RWCU system (Section 01.2).

The licensee identified that operating crews did not adequately communicate and

control the inoperable condition of a control rod during their shifts and shift turnovers

which resulted in a control rod movement prohibited by TS (Section 01.3).

• The licensee identified that a Potential Limiting Condition for Operation was not

entered as required due to improper assessment and documentation when the

conditions specified in a TS-required step of a surveillance instruction (SVI) were not

satisfied. The licensee also identified that the SVI was changed without verifying

that the change did not affect past surveillance test results (Section 01.4).

Maintenance

Overall maintenance activities were effective in improving the material condition of

the plant (Section M1.1).

• The safety tag-out for recirculation system flow control valve (FCV) actuator work did

not isolate the FCV from the reactor coolant system and a failure of the FCV packing

occurred during the actuator work. Several protective barriers in the initiation,

authorization, ard work relea:a process broke down to produce a potentially

hazardous situation for workers. Operators had to respond to minimize a personnel

hazard and isolate a reactor coolant leak. Other personnel accumulated radiation

dose during the leak recovery actions. This event resulted in a violation of NRC

requirements. Another tagging error occurred during restoration of a tag-out which

caused an engineered safety feature actuation (Sections M1.2 and M1.3).

• An operator identified that test equipment remained installed on a Reactor Core

Isolation Cooling (RCIC) system valve after testing was complete. However, the

failure of a maintenance worker to consider the need for environmental qualification

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of the valve and to fully communicate the status of the work activity to operations '

personnel nearly resulted in rendering the RCIC pump inoperable (Section M1 A),

• The licensee identified that an incorrect relay was removed instead of the one

specified under a work order. Inadequate self-checking techniques failed to detect a

work planning error and caused an initiation of an isolation signal that was an

unnecessary challenge to the operators (Section M1.5).

Plant Support

The fire brigade responded well to smoke in the Service Building elevator (Section

F1,1).

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Report Details

Summarv of Plant Status

The unit remained in its sixth refueling outage until October 20,1997, when the licensee

began a unit startup. The startup was completed on October 23, and power was increased

until October 28, when full power was attained. On October 29, power was reduced to

about 70 percent to adjust control rod positions and the plant was retumed to full power on

October 30. The unit operated at full power for the rest of the inspection period except for

one minor power reduction for valve testing,

l. Operations

01 Conduct of Operations

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of

ongoing plant operations.

01.1 General Comments

a. Inspection Scope f71707)

The inspectors observed many pre-job briefings, shift turnover briefings, and many of

the activities that had been discussed at the pre-job briefings. The inspectors also

observed preparations for startup from refueling outage 6 (RFO6), and the

subsequent startup. Continuous inspection was conducted during the plant startup

and initial power increase,

b. Observations and Findinas

Shift supervisors and unit supervisors consistently initiated briefings prior to

significant plant evolutions. Written briefing summaries were used for almost all

briefings. Operations supervisors presented pertinent information to applicable plant

personnel during these briefings. The briefings usually involved considerable

discussion between team members on responsibilities and expectations. A detailed

written plan was developed for the startup, with specific tasks assigned to individuals

in advance to allow them to familiarize themselves with task requirements, and in

some cases, to practice the task on the simulator, in one case, the specific task

description was not adequate (see Section M1.4). Operations personnel were well

prepared for startup activities, and kept supervision informed of abnormal conditions.

Three-legged communications were normally followed during RFO6, plant startup,

and normal plant operations. The control room appeared crowded at various times

during the plant startup. Although no detrimental effects were noted, operations

personnel stated that they were periodically challenged by the amount of activity in

the control room. There were no operator errors during the plant startup and power

ascension.

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c. Conclusions

Thorough preparations were made prior to returning the unit to power following

RFO6. The startup was well controlled and accomplished without error, Briefings

were generally thorough and clear.

01.2 Reactor Water Cleanuo Isolation

a. Insoection Scope (71707)

i

The inspectors reviewed the circumstances and interviewed personnel involved in

the inadvertent isolation of the Reactor Water Cleanup (RWCU) system during the

performance of a Surveillance Instruction (SVI).

b. Observations and Findinos

During the performance of the Division 1 Loss of Offsite Power (LOOP) Tert,

SV!-R43-T1337, Revision 1 (March 1994), on October 10,1997, the RWCU tvstem

automatically isolated due to an incorrect bypass switch position. The SVI requ; ad

the verification of the RWCU leak detection bypass switch in the bypass position.

Contrary to this requirement, the operator conducting the verification failed to identify

that the switch was actually in the normal position, even though its position was

readily visible. Subsequent steps of the SVI initiated ar; RWCU isolation signal and

actuation due to the incorrect position of the bypass switch. There was no actual

plant condition that required an RWCU isolation, and the isolation had no potential or

actual safety consequences. Ti.is personnel error was promptly identified and

reviewed by the licensee through its corrective action process. The issue was

discussed with operations personnel to curb future self-checking failures. Technical

Specification 5.4.1.a specifies, in part, that

written procedures be established, implemented, and maintained covering the

applicable procedures recommended in Appendix "A" of Regulatory Guide (RG)

1.33, Revision 2. Technical Specification 5.4.1.a applies to SVI-R43-T1337and the

failure to follow the SVI is considered a violation of TS 5.4.1a. This non-repetitive,

licensee-identified and corrected violation is being treated as a Non-Cited Violation

(NCV 50 440/97016-01a(DRP)), consistent with Section Vll.B.1 of the NRC

Enforcement Policy. The licensee reported this event to the NRC as an engineered

safety features (ESF) actuation via the NRC Emergency Notification System (ENS).

The licensee appropriately withdrew the report because 10 CFR 50.72 did not

require reporting an invalid actuation of an RWCU isolation.

c. Conclusions

An operator's failure to ensure the RWCU leak detection bypass switch was in the

bypass position during the performance of LOOP testing caused an inadvertent

isolation of the RWCU system.

01.3 Movement of an Inoperable Control Rod

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a. Insoe: tion Scope (71707)

The inspectors reviewed the circumstances associated with and interviewed

personnel involved in a control rod movement that had been conducted in violation of

the requirements of TS 3.10.4 during control rod drive (CRD) testing,

b. Observations and Findinos

On October 14,1997, operators, with the plant in cold shutdown, were preparing for

startup after RFO6. As part of these activities, CRD hydraulic control units (HCUs)

had been serviced. Following HCU restoration, control room personnel commenced

CRD testing. At approximately 1:00 p.m., control room personnel received an i

ennunciator and indication that the HCU for CRD 18-39 had a scram accumulator

leak. The accumulator leak detection equipment was removed from service to permit

nitrogen recharging of the accumulator. This rendered the CRD for Rod 18-39

inoperable. During recharging, a leaking instrument fitting was discovered and l

Instrumentation and Controls (l&C) personnel were called to assist. Day shift

operations personnel failed to provide administrative controls for CRD 18-39 by

ensuring the condition was deficiency tagged, documented in logs, and tumed over

to the oncoming crew. l

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After the 7:00 p.m. shift turnover, rod testing recommenced. At approximately 7:30

p.m., a reactor operator (RO), under direct senior reactor operator (SRO)

supervision, withdrew Rod 18-39 from the reactor core approximately 12 inches, then

inserted it. All other rods remained fully inserted at that time. The RO Snd the SRO

involved in the rod movement each failed to identify that the CRD was inoperable I

due to the accumulator leak detection equipment having been removed from service.

At approximately 10:00 p.m., l&C technicians informed the RO that the scram

accumulator leak detection instrumentation for the CRD 18-39 HCU was isolated.

The operators restored the instrumentation to service and noted that accumulator

pressure was approximately 1340 pounds per square inch - gauge (psig) with reactor

vessel pressure at 0 psig. This was below the TS-required rainimum pressure of

1520 psig. The operators then declared the CRD inoperable, initiated a deficiency 1

tag for the leak and initiated a potential issue form (PIF) for the personnel error. The

ability to scram the rod is a necessary part of reactivity control that is required to be

maintained whenever rods are withdrawn from the core, it was fortuitous that the .

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accumulator pressure was above the actual reactor pressure so that Rod 18-39

could have been scrammed if necessary. The licensee subsequently investigated

this event, notified the NRC via the ENS, initiated corrective actions and submitted

Licensee Event Report (LER)97-014. Opedions personnel involved were

counseled and other operations personnel were briefed to prevent recurrence.

Technical Specification Limiting Condition for Operation 3.10.4 required that scram I

accumulator pressure be greater than 1520 psig, as referenced in TS 3.9.5, with a j

rod withdrawn from the core. Contrary to these requirements, control Rod 18-39 was

partially withdrawn from the core with scram accumulator pressure less than 1520

psig. This non-repetitive, licensee-identified and corrected violation is being treated

as a Non-Cited Violation (NCV 50 440/97016-02(DRP)), consistent with Section

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Vll.B.1 of the NRC Enforcement Policy.

c. Conclusions

The inoperable condition of the HCU for CRD 18-39 was not adequately

communicated and controlled by operating crews throughout their shifts and during ,

shift turnover. This allowed a control rod movement which was prohibited by TS.

Due to the low pressure in the reactor vessel, the accumulator had sufficient

pressure to scram the rod if necessary.

01.4 Emeraency Diesel Generator (EDG) Operability Determination

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a. Inspection Scoce (37551. 71707 and 92901)

ihe inspectors reviewed SVI-R43 T5367, "LPCI B and C Initiation and Loss of EH12

Response Time Test," Revision 6 (February 1996) and reviewed the licensee's initial

response, investigation, and reporting of a failed TS-required step of the SVI.

b. Observations and Findinas

in response to Generic Letter 96-01, " Testing of Safety-Related Logle Circuits," the

licensee conducted a review of surveillance instruction SVI R43-T5367 which tested,

in part, the EDG loading sequence during a LOOP or loss of coolant accident

(LOCA) event. A procedure reviewer determined that Step 5.1.4.2.1 of the SVI,

which required verification that Emergency Service Water (ESW) Pump 'B" would

start within 18 to

22 seconds after EDG breaker closure, should have been marked with a "$" sign

signifying that it was a TS-required step. On July 21,1997, the SVI was changed to

include this designation.

On October 12,1997, during RFO6, SVI-R43-T5367 was performed. When Step

5.1.4.2.1 was conducted, ESW Pump "B" started 24.6 seconds after EDG breaker

closure, which was outside of the required time period specified in the step.

Operations personnal were informed of the failure to satisfy the conditions specified

in Step 5.1.4.2.1 of the SVI at about 3:30 p.m. Two PIFs were initiated by operations

personnel. The first was initiated at about 4:00 a.m. on October 13; however, a TS

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Limiting Condition for Operation (LCO) or a potential LCO (PLCO) was not initiated

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nor did operations personnel request an EDG operability determination at that time.

A second PIF, 97-2128, was signed by the Shift Supervisor at 9:08 p.m. This PIF

initiated PLCO P97-1057, but this PLCO identified the ESW pump as the concem,

not the EDG, it was not until the aftemoon of October 14,1997, that a PLCO was

initiated for the EDG. Perry Administrative Procedure (PAP) 1105, " Surveillance

Test Control," Revision 8 (July 1995), required, in part, that operations personnel

take immediate actions to evaluate the operability of equipment and enter the

applicable TS LCO when the conditions specified in a "S" denoted step within a TS

SVI are not satisfied.

The licensee also determined that the conditions specified in this step had not been

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satisfied when the surveillance test was performed during refueling outage 5 (RFOS);

however, this was not considered or evaluated by the procedure reviewer when the

SVI was revised in July 1997. Perry Administrative Procedure 0522, ' Changes to

Procedures and Instructions," Revision 8 (June 1996), stated, in part, that the

change process would ensure all proposed changes met the criteria described in the

In-Depth Review Checklist (IDRC) per PAP-0507, ' Preparation, Review, and

Approval of instructions," Revision 11 (June 1996). The IDRC of PAP-0507 required,

in part, that the document containing the proposed changes be adequately detailed

- for verification and sign off of acceptance

criteria, TS acceptance criteria be clearly stated, and that required follow-up actions

be taken when the proposed document identified an adverse impact on completed

activities.

Technical Specification 5.4.1.a specifies, in part, that written procedures be .

established, implemonted, and maintained covering the applicable procedures

recommended in Appendix "A" of Regulatory Guide (RG) 1.33, Revision 2.

Technical Specification 5.4.1.a applies to PAP-0522,0507, and 1105. The failure of

operations personnel to immediately initiate a TS LCO or PLCO for the Division 2

EDG once the conditions specified in a "$" step of an SVI were not satisfied, is an

example of a violation of TS 5.4,1.a in that PAP-1105 required an immediate

operability evaluation and entrance into the applicable LCO or PLCO when Step

5.1.4.2.1 conditions were not satisfied. The failure of the procedure reviewer to

ensure that required follow-up actions were taken when the proposed change to SVI.

R43 T5367 resulted in an adverse impact on completed activities (i.e., conditions

. specified in a ?$' step were not satisfied when the subject SVI was performed during '

RFO5) is an additionst example of a violation of TS 5.4.1.a. Corrective actions

included both engineering and operations personnel required training on the

significance of SVI failures, the need for retrospective review; when changing

procedures, and

the need for prompt equipment operability determinations This non-repetitive,

licensee-identified and corrected violation is being treated as a Non Cited Violation

(50-440/97016-01b and c (DRP)), consistent with Section Vll.B.1 of the NRC

Enforcement Policy.

The Division 1 and 2 EDGs were rated at 7000 kilowatts (kw), which was

significantly greater than the loao demand on the divisional busses. The EDG l

maximum expected load during LOOP or LOCA conditions was 5600 kw. Previous

engineering evaluations showed that all buss loads could start at time zero without

sdversely affecting the EDG Further, ESW pump "B" was not needed for cooling

until at least 90 seconds after the EDG started. Therefore, the EDG would not have

been adversely effected by the ESW pump loading at 24.6 seconds. The licensee

indicated that a review of the SVI to determine if Step 5.1.4.2.1 requires a "$"

designation would be completed.

c. Conclusions

The lack of a thorough review of SVI-R43-T5367 before its revision resulted in the

failure to identify that the conditions specified in a step of the SVI designated as TS-

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required, were not satiefied when the SVI was performed during RFOS. In addition,

when the conditions specified in this step were not satisfied when the SVI was

. performed during RFO6, operators failed to recognize that an immediate operability

determination and entrance into the applicable LCO or PLCO was needed. These

problems resulted in the identification of two examples of a Non-Cited Violation.

01.5 Operations Staff Resources

Several operations personnel, including two shift supervisors and a shift technical

advisor, left the licensee's employment during the inspection period. The operation's

department staffing remained above and beyond minimum staffing levels required by

NRC regulations and no immediate concems were noted with the licensee's ability to

effectively operate the plant. Ti.a licensee evaluated this situation and took several

administrative steps to address this situation.

02 Operational Status of Facilities and Equipment

O2.1 Drvwell Closeout

a. Inspection Scope (71707 and 92901)

The inspectors accompanied a plant operations representative for the closeout

inspection of the drywell area of the plant.

b. Observations and Findinas

The drywell was inspected on October 19,1997, with no major deficiencies noted.

The drywell and suppression pool were well prepared for startup. Some minor

debris, such as pieces of duct tape, were discovered by the inspectors during the

walkdown and removed by an operations representative. Other minor debris was

noted in the suppression pocl, and a piece of tape was identified in a safety relief

valve cover. These items were removed by equipment cleaners prior to startup,

c. Conclusions

The operational status of facilities and equipment was appropriately addressed by

operations personnel prior to drywell closecut.

07 Quality Assurance in Operations

07.1 Corrective Action

a.- Inspection Scope (71707) - -

The inspectors evaluated a licensee management initiative to focus attention on

timeliness of corrective actions.

b. Observations and Findinas

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Licensee senior management instructed the corrective action program administrator

to maintain a list of the 20 oldest potential issue forms (PlFs) with incomplete

corrective actions. The list was included in the handout for the daily managers'

meeting and the 10 oldest PlFs were discussed at each meeting, Individuals

responsible for completing corrective actions presented their plans for completing the

actions and identified areas where they needed assistance. When the initiative

began, the oldest PIF was from 1994, at the end of the inspection period the oldest

PlF was from 1995.

c. Conclusions

Licensee management's action and oversight were effective in focusing attention on

-the completion of older corrective actions.

08 Miscellaneous Operations issues

08.1 (Closed) LER 50-440197-12-00: ' Insufficient Procedural Guidance Results In Reactor

Protection System Actuation." On September 23,1997, at about 12:16 a.m., control

room operators repositioned the reactor mode switch without realizing that it would

cause a reactor protection system actuation. This event was discussed in Inspection

Report (IR) No. 50-440/97012. The corrective actions discussed in the LER,

including procedure improvements W operator training, are adequate to prevent

recurrence.

08.4 (Closed) LER 50-440197-14-00: ' Withdrawal ofInoperable Control Rod Results in

Operation Prohibited by Technical Specifications." This event is discussed in

Section 01.3 of this IR.

II. Maintenance,

M1 Conduct of Maintenance

M1,1 General Comments

a. Insoection Scoce (61726. 62707. 71500 and 92902)

The inspectors used Inspection Procedures 61726 and 62707 to evaluate several

work activities and surveillance tests. The inspectors observed emergent work as

well as planned maintenance conducted during the refueling outage, plant startup,

and normal operations.

b. Observations and Findinos

The activities observed were generally accomplished effectively with appropriate use

of drawings and written instructions. Licensee personnel continued to maintain a low

threshold in using the PIF process and equipment deficiency tags to identify issues

and potential problems. This included examples of personnel identifying their own

errors and situations that could contribute to errors or problems that had not yet

occurred. The inspectors observed that design changes were implemented to

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impreve the reliability of the reactor feedwater booster pumps (RFBPs). The pre job

briefing for testing the "C" RFBP and placing it in service was thorough and included

clear and detailed communications among operators, maintenance personnel and

engineers. Supervisors emphasized the importance of prompt communications of

detailed observations, conservative decision making, self checking, and proper

preparation. The overall maintenance backlog was reduced and maintained below

the hcensee's long temi goal. An aggressive approach to steam and water leakage

improved radiological conditions and reduced the amount of radioactive effluents-

discharged. The inspectors noted improvements in the maintenance of work records

during the conduct of work, and as a result less effort was required near the end of

RFO6 to gather missing inforrnation to close out work documents,

c. Conclusions

Although exceptions are discussed in this report, overall maintenance activities were

effective in improving the material condition of the plant.

M1.2 Poor Safety Taaaina Led to a Reactor Coolant Leak

a. inspection Scoce (62707. 71707. and 92902)

The inspectors reviewed the circumstances surrour, ding the reactor recirculation

system flow control valve (FCV) packing failure during FCV actuator work.

b. Observations and Findinot

On October 6,1997, with the plant in cold shutdown, contract maintenance workers

were sprayed with reactor coolant as they worked on the actuator for the "A" Reactor

Recirculation FCV in the drywell. The workers were contaminated but no

appreciable dose was received and no personnelinjuries occurred as a result of this

event. Safety tag-out 27868 for work on the "A" FCV did not isolate the work area

from the reactor coolant system (RCS). Before beginning work, the workers asked

their supervisor if the work area needed to be isolated from the reactor cc Mnt

system. The supervisor assumed that the relevant piping was still drained as it had

been the previous day and indicated to the workers that the tag-out was proper.

However, the piping had been refilled and was open to the reactor coolant system.

During the actuator work, the FCV packing cartridge failed and the workers were

sprayed with water. A non-licensed operator observed the water spray (estimated at

100 gallons per minute (GPM)) and notified the control room. The control room

operators promptly closed the maintenance valves for the recirculation loop and the

leakage was reduced to about 10 GPM. The operators did not observe any RCS

level decrease.

Technical Specification 5.4.1.a specifies, in part, that written procedures be

implemented covering the applicable procedures recommended in Appendix "A" of

RG 1.33,

Revision 2. Appendix "A" of RG 1.33 recommended that safety tagging be

implemented by a written procedure. Perry Administrative Procedure-1401, " Safety

Tagging,"

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Revision 8 (January 1995), required, in part, that tag-outs be prepared and verified to

adequately isolate potential hazards to personnel and equipment prior to the

commencement of work.

Safety tag out 27868 was not adequately prepare ( and verified to isolate personnel

or equipment from the potential hazards associated with the flow control valve

actuator work. This was a violation (VIO 50 440/97016-03(DRP)) of TS 5.4.1.a.

Although this was a licensee-identified and corrected violation, it did not meet the

requirements for enforcement discretion of Section Vll.B.1 of the NRC Enforcement

Policy because it was a repetitive violation. Violation 50-440/97007 01b(DRP),

identified on June 2,1997, occurred because licensee personnel did not adequately

verify that a tag-out adequately isolated a potential hazard to personnel. Also, in the

recent past there have been several plant events and problems that have occurred

because of poor communications. The investigation for PlF 97-1962, which was

initiated for this event, identified 12 contributing factors for this violation; 7 involved

poor communications. In addition to the personnel and equipment hazard

associated with this event, additional personnel radiation dose was accumulated

during the cleanup of the drywell that was required as a result of the spilled reactor

coolant.

c. ConcluJ i ons

The safety tag-out for recirculation system FCV actuator work did not isolate the FCV

from the reactor coolant system and a failure of the FCV packing owurred during the

actuator work. Several protective barriers in the initiation, authorization, and work

release process broke down to produce a potentially hazardous situation for workers. '

Operators had to respond to minimize a personnel hazard and isolate a reactor

coolant leak. Other personnel accumulated radiation dose during the leak recovery

actions.

M1.3 Poor Control of Safety Taaaina Caused ESF Actuation

a. Inspection Scoce (62707 and 92902)

The inspectors reviewed the licensee's evaluation of an ESF actuation that was

caused by incorrect sequencing of a restoration from a safety tag-out.

b. Observations and Findinas

On October 9,1997, with the plant shut down during refueling activities, operators

were removing safety tags from the CRD hydraulic system. Parry Administrative

Procedure-1401, " Safety Tagging," Revision 8 (January 1995), Step 6.4.13, requires

that the tag-out reviewer consider the need to specify an order to be followed when

removing tags. The SRO in charge of removing the tags and resto"ng the CRD

hydraulic system (reviewer) did not adequately consider the order of removing the

tags for tag-out 27835 and when the valves for the CRD hydraulic system were

restored to their normal position, normal leakage filled the scram discharge volumes

until a high scram discharge volume scram occurred. All rods were already fully

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inserted so there was no rod motion. The personnel involved were counseled. The

failure to properly use written instructions appropriate to the circumstances for this

work was an additional example ct a TS 5.4.1.a violation. The corrective actions for

previous tagging errors could not have reasonably been expected to have prevented

this event from occurring. Therefore, this non-repetitive, licensee-identified (as a

result of a self revealing event), and corrected violation is being treated as a Non-

Cited Violation (50-440/97016-01d(DRP)), consistent with Section Vll.B.1 of the

NRC Enforcement Policy.

c. Conclusions

Personnel errors in restoring a safety tag-out caused an ESF actuation and resulted

in the identification of an additional example of a TS 5.4.1.a Non-Cited Violation.

M1.4 Improper Control of Test Eauipment

a. Inspection Scope (61726. 62707. and 92902)

The inspectors reviewed the actions associated with the failure to remove test

equipment from a reactor core isolation cooling (RCIC) system motor operated valve

(MOV) following a test.

b. Observations and F!ndinos

Post-outage RCIC system testing included motor operated valve (MOV) testing

during both cold and hot conditions. On Octder 20,1997, the limit switch cover for

MOV 1E51-F0019 was removed to allow the installation of test equipment for the

cold test. Once the cold test was completed, rather than remove the equipment, the

technician left it in place due to the need to perform an additional test on the MOV at

hot conditions. However, in the time between the two tests, the reactor pressure

was to be raised above 200 psig, the pressure above which environmental

qualification (EQ) of the valve is needed. The MOV limit switch cover was required

to be installed to assure EQ of the valve. The decision to leave the cover off, and

the potential inoperability of the valve, were not adequately communicated to

operations. Prior to the reactor pressure reaching 200 psig, this condition was

identified by an operator performing rounds in the area. The test equipment was

removed and the MOV limit switch cover was installed. A subsequent safety

evaluation determined that the RCIC pump was operable because EQ for the valve

was not needed for the plant conditions at the time this condition was identified. It

was fortuitous that the timing of the operator identifying this problE m coincided with

reactor pressure being below 200 psig.

c. Conclusions

The failure of a maintenance worker to consider the need for environmental

qualification of MOV 1E51-F0019 and to fully communicate the status of the work

activity to operations personnel nearly resulted in rendering the RCIC pump

inoperable. However, due to the discovery and removal of the test equipment prior

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to the reactor reaching 200 psig, the RCIC pump remained operable.

M1.5 Incorrect Relav Reolacesi,

a. Inspection Scope (61726. 62707. and 92902)

The inspectors reviewed the actions associated with the replacement of en incorrect

relay under Work Order (WO) 97-1918.

b. Observations and Findinas

On November 20,1997, relay 1821H K4C (labeled "CK") was removed instead of

relay 1C71 A-K4C (labeled 'CD"). Due to a planning personnel error, the WO

incorrectly identified the C71A-K4C relay as "CK." The removal of the incorrect relay

resulted in a half logic actuation of the main steam line isolationi function.

Because ofinadequate self checking techniques, maintenance personnel failed to

detect the work planning error. The event was promptly ident;fied, the correct relay

was replaced, and the isolation was reset. This non-repetitive, licensee-identified

and corrected violation is an additional example of a TS 5.4.1.1 violation and is being

treated as a Non Cited Violation (50 440/97016-01e(DRP)), consistent with Section

Vll.B.1 of the NRC Enforcement Policy.

c. Conclusions

inadequate self-checking techniques failed to detect a work planning error and

caused an initiation of an isolation signal that was an unnecessary challenge to the

operators.

M8 Miscellaneous Maintenance lasues (92700)

M8.1 (Closed) LER 50-440197-007-00: ' Loss of Electrical Power to Reactor Protection

System Bus Due to Electrical Protective Assembly Trip Results in Engineered Safety

Feature Actuations." On July 13,1997, at about 11:58 a.m., electrica. power from

the Division 2 normal power source to Reactor Protection System Bus "B' was lost.

This event was discussed in inspection Report (IR) No. 50-440/97009. The cause of

the event was determined to be unreliable operation of the electrical protective

astembly logic control board. This problem was similar to that reported in LER 97-~

003-00. Completion of corrective actions will be evaluated during the inspectors'

review of LER 97-003-00.

M8.2 (Closed) LER 50-440197-01' ' Loss of Electrical Power to Reactor Protection

System Bus Due to Electr... .,tective Assembly Trip Results in Engineered Safety

Feature Actuations." This re, ilon to LER 97-010-00 corrected an error the licensee

identified in the original LER which incorrectly stated that the event caused a RCIC

isolation. There was no RCIC isolation. Therefore, the event had slightly less

potential safety consequences than originally indicated. Licensee Event Report 97-

010-00 was closed in IR No. 50-440197012 because the corrective actions for LER

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- . . . -- .

97-010-00 will be evaluated during the inspector's review of LER 97-003-00. This

revision had no impact on that planned review.

M8.3 {Dlosed) LER 50-440/97-011-00: " Technical Specification Surveillance Test

- Performance Results in Engineered Safety Feature Actuations." On September 21,

1997, at about 4:S3 a.m., with the plant shutdown during refueling operations, I&C

technicians performing a surveillance test caused an inadvertent pressure trans!ent

in the reference leg for two level instruments. The pressure transient caused a false

reactor pressure vessel low water level ESF actuation. All safety equipment.

operated as required for the existing plant conditions and there was no adverse

effect on plant equipment. The corrective actions discussed in the LER, including

procedure improvements and l&C technician training, are adequate to prevent

recurrence.

M8.4 LQggn) LER 50-440197-013-00: ' Control Rod Drive Hydraulic System Maintenance

Activities Result in Reactor Protection System Actuations." This LER reported two

similar events regarding safety tagging of the control rcd drive hydraulic system.

The event that involved an ESF actuat'on on October 9,1997, is discussed in

Section M1.3 of this inspection report. No additional inspection is required for that

event. The event that occurred on October 11,1997, is the subject of IR No. 50-

440/97022.

Ill. Enaineerina

E2 Engineering Support of Facilities and Equipment

E2.1 Suporession Pool LevelIndication

a. inspection Scope (37551. 61726. and 92903)

The inspectors reviewed the licensee's initial evaluation of larger than expected

suporession poollevelindication oscillations during a high pressure core spray

(HPCS) system surveillance test,

b. Observations and Findinos

During a surveillance test of the HPCS system, which directed system flow to the

suppression pool v!L the test retum line, control room operators observed that

suppression poollevelindication oscillations were larger than had been observed in

the past. Operators dispatched to the containment to observe the surface of the

- suppression pool determined that the oscillations were not as large as the

instrumentation indicated. The operators documented their observation with PlF 97-

2168. During a discussion with the inspectors, engineers stated that the newly

installed emergency core cooling systems strainer in the suppression pool appeared

to be causing larger pressure oscillations which had been indicated as level

- oscillations by the pressure differential level indication,

in performing its safety function, HPCS would not be retuming flow to the

15

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suppression pool, as it did in the test, so the strainer would not impact the HPCS

safety function. The inspectors and the licensee monitored suppression poollevel

indications during RCIC operation and safety relief valve (SRV) testing because

RCIC and the SRVs discharge steam to the suppression pool when they are

required to perform their safety functions. The inspectors noted only minor variations

in levelindication during RCIC and SRV operations. The licensee performed

another HPCS test with temporary video cameras in the containment and verified

that actual suppression poollevels were not fluctuating more than expected. The

licensee completed its investigation of PIF 97-2168 and concluded that the design of

the level instrument sensing lines allowed an undesirable accumulation of air in the

lines. The licensee concluded that the lines could be vented sufficiently to maintain

the operability of the levelinstruments. However, the licensee developed eight

corrective actions for the PlF, which included development of a more thorough

venting method and evaluation of a modification to the sensing lines. The inspectors

will review the implementation of the corrective actions for this phenomenon during a

future inspection (IFl 50-440/97016-04(DRP)).

c. Conclusions

The accumulation of air in the suppression poollevelinstrument sensing lines led to

indications that level oscillations during a HPCS system surve!llance test were larger

than they actually were.

E2.2 RCIC Govemor Valve

a. Inspection Scope (37551 and 92903)

The inspectors reviewed the trip and troubleshooting of the RCIC turbine during

startup after RFO6.

b. Observations and Findinos

During plant startup and heat up, the RCIC turbine was operated for Inservice

Inspection (ISI). The cold start of the turbine for the ISI was normal, as were other

cold starts. Near the end of the ISI, the RCIC turbine unexpectedly tripped, possibly

as a result of its controls being gently bumped by personnel working on the turbine,

During two immediate attempts to restart the hot turbine, it also tripped. The

licensee delayed plant startup to disassemble the governor valve and thoroughly

investigate the cause of the trips. The investigation revealed that the manufacturing

tolerances of the turbine governor valve stem and carbon spacer rings did not match

design tolerances. The stem was replaced with a component that was acceptable,

but was more susceptible to a previously exhibited corrosion problem. The licensee

completed its corrective action program investigation near the end of the inspection

period and identified several corrective actions. The inspectors need to evaluate the

past operability of the RCIC turbine, the adequacy of corrective actions, the

adequacy of the surveillance testing methods, and the root cause of the failed stem

and spacer rings. This will remain an Unresolved item (URI 50-440/97016-

05(DRP)) until the inspectors complete their eva!uation.

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c. Conclusions

Following unexpected trips of the RCIC tu bine, the licensee promptly completed a

thorough investigation to ensure the RCIC system was operable, issues idenufied

during the investigation require further NRC review.

IV. Plant Sucoort .

F1 Fire Protection Staff Knowledge and Performance

During plant startup, the fire brigade responded to the report of smoke from the

service building elevator. The brigade responded within 2 to 3 minutes and

immediately discovered the source of smoke was the elevator motor. Appropriate

equipment was deenergized, and steps were carried out promptly to secure the area.

No fire was observed. The fire brigade was knowledgeable of the proper actions to

take and demonstrated that their response training was effective.

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management

at the conclusion of the inspection on December 1,1997. The licensee

acknowledged the findings presented. The inspectors asked the licensee whether

any materials examined during the inspection should be considered proprietary. No

proprietary information was identified.

,

17

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_ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ - _ _ _ _ _ __

PARTIAL LIST OF PERSONS CONTACTED

Licensee

L. W. Myers, Vice President, Nuclear

W. R. Kanda, General Manager Nuclear Power Plant Departrnent

T. S._ Rausch, Director, Quality and Personnel Development Department

N. L Bonner, Director, Nuclear Maintenance Department-

R. W. Schrauder, Director, Nuclear Engineering Department

H. W. Bergendahl, Director, Nuclear Services Department

J. Messina, Operations Manager-

J. T. Sears, Radiation Protection Manager

F. A. Kearney, Superintendent Plant Operations

,

18

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INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 61726: Surveillance Observations

IP 62707: Maintenance Observation

IP 71500: BOP-

IP 71707: Plant Operations

IP 71714: Cold Weather Preparations

IP 71750: Plant Support Activities

IP 92700: Onsite Follow-up of Written Reports of Non-routine Events at Power Reactor

Facilities

IP 92901: Follow-up - Plant Operations

IP 92902: Follow-up - Maintenance

IP 92903: Follow-up - Engineering

IP 92904 - Follow-up - Plant Support

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-440/97016-01a(DRP) NCV Inadvertent RWCU lsolation

50-440/97016-01b(DRP) NCV Entering incorrect PLCO

50-440/97016-01c(DRP) NCV Improper Procedure Change

50-440/97016-01d(DRP) NCV Improper Safety Tag Restoration

50-440/97016-01e(DRP) NCV Incorrect Tlelay Replacement

50-440/97016-02(DRP) NCV Movement of Inoperable Control Rod

50-440/97016-03(DRP) VIO Improper Safety Tagging

50-440/97016-04(DRP) IFl Suppression Pool Level Concerns

50-440/97016-05(DRP) URI Unexpected RCIC Turbine Trips

Closed

50-440/97016-01a(DRP) NCV Inadvertent RWCU lsolation

- 50-440/97016-01b(DRP) NCV Entering Incorrect PLCO

50-440/97016-01c(DRP) NCV Imprope; Procedure Change

50-440/97016-01c(DRP) NCV Improper Safety Tag Restoration

19

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-- _-

50-440/97016-01e(DRP) - NCV -Incorrect Relay Replacement

-

50-440/97016-02(DRP) -NCV Movement of Inoperable Control Rod

50-440/97-007-00 LER- Loss of Electrical Power to Reactor Protection system

Bus Due to Electrical Protective Assembly Trip Results

in engineered Safety Feature Actuations

50-440/97-010-01 LER Loss of Electrical Power to Reactor Protection system

Bus Due to Electrical Protective Assambly Trip Results

in Engineered Safety Feature Actuations

50-440/97-011 00 LER Technical Specification Surveillance T:st Performance

Results in Engineered Safety Feature Actuations

'

50-440/97-012-00_ LER Insufficient Procedural Guidance Results in Reactor

Protection System Actuation

- 50-440/97-014-00 LER Withdrawal of Inoperable Control Rod Results in

Operation Prohibited by Technical Specifications

Discussed

50-440/97-013 00 LER Control Rod Drive Hydraulic System Maintenance

Activities Result in Reactor Protection System

Actuations -

b

(

20

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LIST OF ACRONYMS AND INITIALISMS

CFR Code of Federal Regulations

CRD Control Rod Drive

-EDG Emergency Diesel Generator

ENS Emergency Notification System

EPA ' Electrical Protective Assembly

EQ Environmental Qualification - *

ESF. Engineered Safety Feature

ESW Emergency Service Water

HCU Hydraulic Control Unit

HPCS High Pressure Core Spray

I&C Instrumentation and Control

IDRC In-Depth Reviewer Checklist

@

'

IFl Inspector Followup Item ,

IR Inspection Report  ;

KW Kilowatts  !

LCO Limiting Condition for Operation

LER Licensee Event Report

LOCA Loss of Coolant Accident

LOOP Loss of Offsite Power

MOV Motor Operated Valve

NCV Non-Cited Violation

NRC Nuclear Regulatory Commission

PAP Perry Administrative Procedure

PDR Public Document Room

PIF Potential issue Form

PLCO Potential Limiting Condition for Operation

PSIG Pounds per Square Inch, Gage

RCIC Reactor Core Isolation Cooling

RCS Reactor Coolant System

RFBP Reactor Feedwater Booster Pump

RFO5 Refueling Outage 5

RFO6 Refueling Outage 6

RG Regulatory Guide

RI Resident inspector

RO Reactor Operator

RWCU Reactor Water Cleanup

RPS- Reactor Protection System

SRI Senior Resident inspector

SRO Senior Reactor Operator

SRV- Safety Relief Valve

SVI . Surveillance Instruction

TS Technical Specification

URI Unresolved item

USAR Updated Safety Analysis Report

VIO Violation

WO Work Order 21

.

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