ML20217R014

Insp Repts 50-454/98-09 & 50-455/98-09 on 980223-0406. Violations Noted.Major Areas Inspected:Operation, Maint Surveillance & Plant Support

ML20217R014
Person / Time
Site:	Byron
Issue date:	05/05/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217Q928	List: ML20217Q926 ML20217Q967 ML20217R014
References
50-454-98-09, 50-454-98-9, 50-455-98-09, 50-455-98-9, NUDOCS 9805130085
Download: ML20217R014 (22)

See also: IR 05000454/1998009

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U. S. NUCLEAR REGULATORY COMMISSION

REGION 111

Docket Nos: 50-454;50-455

License Nos: NPF-37; NPF-66

Report No: 50-454/455-98009(DRP)

Licensee: Commonwealth Edison Company

Facility: Byron Generating Station, Units 1 and 2

Location: 4450 N. German Church Road

Byron,IL 61010

Dates: February 23 - April 6,1998

Inspectors: E. Cobey, Senior Resident inspector

N. Hilton, Resident inspector

B. Kemker, Resident inspector

D. Muller, Reactor inspector

D. Pelton, Braidwood Resident inspector

T. Tongue, Project Engineer

C. Thompson, Illinois Department of Nuclear Safety

Approved by: Michael J. Jordan, Chief

Reactor Projects Branch 3

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9805130085 990505

PDR ADOCK 05000454

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EXECUTIVE SUMMARY

Byron Generating Station Units 1 and 2 i

NRC Inspection Report No. 50-454/98009(DRP); 50-455/98009(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant

support. The report covers a six-week period of inspection activities by the resident staff and

region based inspectors.

Operations

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The inspectors concluded that overall operator performance during the aborted Unit i

reactor startup on March 6,1998, was good, including the development of trip

contingency actions, the use of procedures and three-way communications. The

inspectors also noted that conservative operating decisions were made, most notably the

decision to shutdown the reactor after failing to achieve criticality at the estimated boron

concentration. The inspectors noted one example where the Qualified Nuclear Engineer

created confusion while attempting to explain the boron concentration limits to the

operating crew (Section 01.2).

• The inspectors concluded that overall operator performance during restart on March 7,

1998, of the Unit i reactorwas good. The criteria for startup termination, based on boron

concentration and dilution volume, were clearly stated and fully understood. This

alleviated the confusion that was present during the aborted startup the previous night. j

The inspectors also concluded that procedure usage, crew communication, and crew

briefings were effective (Section 01.3).

- Observed portions of low power physics testing were conducted in a safe manner. Each

reactivity manipulation was closely monitored by the Unit Supervisor. However,

communications between the Qualified Nuclear Engineer and the Unit 1 Nuclear Station

Operator did not meet the station management's expectations for three-way

communications. At times unnecessary personnel congregated in the area of the center

desk and participated in discussions not related to the operation of the plant. Although

these discussions resulted in the background noise level being elevated, no adverse

consequences were noted (Section O1.4).

- The inspectors concluded that the replacement steam generators operated as designed

and the plant responded to the planned transients as expected with no significant

- anomalies noted. In addition, during the replacement steam generator testing, the

inspectors observed effective supervisory oversight of the evolutions and good .

coordination between operators, system engineers, and maintenance personnel. The

inspectors also noted that the control room operators generally adhered to the Nuclear

Operations Division Operations Department Standards (Section 01.5).

• The incpectors concluded that the entry of Unit 1 into Mode 4 (Hot Shutdown) from

Mode 5 (Cold Shutdown) with the seal table room floor drain plugged was a violation of

Technical Specifications and should have been prevented by corrective actions from

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previously identified issues with the floor drain system. The inspectors concluded that

significant contributions to not recognizing the inoperable seal table floor drain were poor

maintenance work request content and documentation, poor problem description on the

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problem identification form, and poor followup by the system engineer's when notified by

mechanics that the floor drains remained plugged. A violation was cited (Section O2.1).

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The inspectors concluded that the licensee's process for maintaining senior reactor

operator licenses active was weak, in that, an Operations Policy Momo allowec; credit for

proficiency to be taken for shift supervisor and administrative shift supervisor positions

contrary to the requirements of 10 CFR Part 55 and the licensee's operating surveillance

test. However, no violations of regulatory requirements were identified because all senior

reactor operators that conducted licensed duties during the quarter met the requirements

of 10 CFR Part 55 and the licensee's operating surveillance procedure. The inspectors

also concluded that several log entries for shift personnel did not meet the licensee

management's expectations (Section O3.1).

. The inspectors concluded that Byron Operating Procedure VC-2, " Shutdown of Control

Room HVAC System," Revision 2, was not appropriate to the circumstances due to an

inadequate technical review during the procedure revision completed on January 7,1998.

In addition, the inspectors concluded that on at least eight occasions, the control room

operators performed this procedure and did not identify the procedural deficiencies and

initiate corrective action, which was not in accordance with licensee managements's

expectations and standards for procedural adherence as described in Nuclear Operations

Division Operations Department Standards, Section Vill, " Procedural Adherence." A

violation was cited (Section O3.2).

Maintenance / Surveillance ,

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The inspectors concluded that each of the observed maintenance activities satisfied the

regulatory requirements. The inspectors also noted that based on the failure to conduct

an appropriate blue check and the additional seat flatness tests required to ensure a

correct seating surface, the licensee did not initially have the necessary expertise to

satisfactorily repair Safety injection Check Valve 1S189568 (Section M1.1).

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The inspectors noted that generally, work requests were adequately controlled and

scheduled; however, an example of unauthorized work in progress was identified by the

inspectors. Approximately 50 work requests were on hold with valid authorizing

signatures which indicated weaknesses in the authorization process. The inspectors

concluded that the control of WRs on hold was undocumented, inconsistent, and

problems were not identified by the licensee. A violation was cited (Section M3.1).

- Plant Support

• The inspectors concluded that the licensee failed to post a contamination area in

accordance with Byron Radiological Protection Procedure 5010-1. A violation was issued

(Section R1.1).

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Report Details

Summary of Plant Status

The licensee completed the Unit 1 steam generator replacement and refueling outage on j

March 8,1998. The licensee subsequently completed physics testing and steam generator j

replacement post modification testing and the unit was operating at or near full power at the end j

of the inspection period. I

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The licensee initiated coastdown operations on Unit 2 during the inspection period in preparation ]

for entering a refueling outage.

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1. Operations

01 Conduct of Operations

01.1 General Comments (71707)

During the inspection period, the inspectors conducted numerous observations of routine

control room activities. The inspectors observed effective heightened level of awareness

briefings for infrequently performed evolutions and good annunciator alarm response.

The inspectors also noted that the control room operators generally adhered to the

Nuclear Operations Division Operations Department Standards. However, the inspectors

also noted several instances where activities did not meet licensee management's

standards and expectations including: (1) three-way closed loop directed

communications were not always utilized; (2) the Unit 2 operators were not monitoring the

computer trend plots specified in the Unit 2 coast down daily order; (3) log entries were

not always sufficiently detailed to allow reconstruction of shift activities; and (4) on one

occasion an equipment operator failed to recognize and initiate action for an out of

specification parameter during a diesel generator surveillance. Overall, the inspectors

concluded that routine operations were conducted in a safe and controlled manner. i

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O1.2 Unit 1 Aborted Startuo Followina Steam Generator Replacement Outaae

a. Inspection Scope (71707 and 50001)

The inspectors observed the heightened level of awareness (HLA) briefing and the initial

Unit 1 startup. The inspectors also reviewed the following procedures:

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• 1BGP 100-2, " Plant Startup," Revision 21

• 1BGP 100-2A1, " Reactor Startup," Revision 11

• 1BVS XPT-4, " Unit 1 Initial Criticality After Refueling and Nuclear Heating Level,"

Revision 12

b. Observations and Findinas

On March 6,1998, the licensee commenced a Unit 1 plant startup following the steam

generator replacement and refueling outage. While monitoring the approach to criticality

using an inverse count rate ratio plot, the Qualified Nuclear Engineer (QNE) identified that

the reactor would not be critical with boron concentration at 1433 parts per million (ppm),

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the estimated critical concentration. During the ensuing discussion with the control room

operators, the QNE could not ensure that the reactor would be critical at a boron

concentration of 1383 ppm (the minimum limit specified in 1BVS XPT-4). In addition, the

QNE created confusion while attempting to explain the technical basis for the limits on

boron concentration. Consequently, ine shift manager directed the crew to halt the ,

startup and make preparations for a reactor shutdown. The inspectors concluded that the

operating crew's decision to retum Unit 1 to a shutdown condition was conservative.

While inserting control rods for the shutdown, control Bank C unexpectedly stopped at

eight steps. As a result, the crew stopped the shutdown and commenced troubleshooting

activities. Since the Bank C rod position and the Bank C demand signal were both at

eight steps, the operators concluded that, even though the manual rod control switch was

in the insert position, the rod control system stopped demanding the insertion of Bank C

at eight steps. After some discussion, the crew determined that inserting a manual trip

was the most appropriate action. After a short control room briefing, a manual trip was i

inserted. Following the reactor trip, the licensee verified all systems functioned as J

expected. Based on the inspectors' observations, the inspectors concluded that the '

licensee's actions were appropriate.

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c. Conclusions 4

The inspectors concluded that overall operator performance during the aborted Unit i

reactor startup on March 6,1998, was good, including the development of trip

contingency actions, the use of procedures and three-way communications. The

inspectors also noted that conservative operating decisions were made, most notably the

decision to shutdown the reactor after failing to achieve criticality at the estimated boron

concentration. The inspectors noted one example where the Qualified Nuclear Engineer-

created confusion while attempting to explain the boron concentration limits to the t

operating crew.

01.3 Unit 1 Startuo After Steam Generator Replacement Outaae

a. inspection Scope (71707 and 50001)

The inspectors interviewed operators and engineering personnel and obseived the

licensee's Hl.A briefing and plant startup activities. The inspectors also reviewed the

procedures referenced in Section 01.2.

- b. Observations and Findinas

On March 7,1998, the licensee corrected the problems observed during the startup and

subsequent shutdown that occurred on the previous midnight shift (see Section 01.2).

Specifically, the licensee: (1) developed a larger acceptance band (consistent with

Technical Specifications (TSs)) for the critical boron concentration, and (2) completed i'

troubleshooting and cleaning electrical contacts on the bank overlap unit in the rod control

system to correct the failure of Bank C to fully insert during the previous shutdown. In

addition, the licensee developed definitive operator actions for specific boron dilution

levels, to address the potential for problems similar to those encountered during the

previous startup. The inspectors observed that the criteria for startup termination, based

on boron concentration and dilution volume, was clearly stated and fully understood.

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The licensee subsequently withdrew control rods to the estimated critical rod height and

then diluted the reactor coolant system (RCS) to the estimated critical boron

concentration. After the dilution was completed, the reactor remained subcritical. Based

on the established boron concentration limits, the crew continued the dilution, but still

within the acceptance range. At 1:50 a.m. on March 8,1998, the reactor achieved

criticality. The chemistry sample indicated that the boron concentration was 1394 ppm, q

approximately 39 ppm below the estimated critical concentration of 1433 ppm. This was I

within the procedural and TS limits. 4

c. Conclusions

The inspectors concluded that overall operator performance during restart on March 7,

1998, of the Unit i reactor was good. The criteria for startup termination, based on boron

concentration and dilution volume, were clearly stated and fully understood. This

alleviated the confusion that was present during the aborted startup the previous night.

The inspectors also concluded that procedure usage, crew communication, and crew

briefings were effective.

01.4 Unit i Low Power Physics Testina i71707)

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The inspectors observed selected portions of Byron Engineering Surveillance (BVS)

1BVS XPT-5, " Unit 1 Rod and Boron Worth Measurements," Revision 9. The inspectors

noted that each reactivity manipulation was closely monitored by the Unit Supervisor.

The inspectors also noted that the communications between the Qualified Nuclear

Engineer and the Unit 1 Nuclear Station Operator routinely did not meet the expectations

for three-way closed loop directed communications delineated in the Nuclear Operations

Division Operations Department Standards,Section IX, " Communications." In addition, i

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the inspectors noted that at times the decorum in the control room declined, in that,

unnecessary personnel congregated in the area of the center desk and participated in

discussions not related to the operation of the plant. Although these discussions resulted

in the background noise level being elevated, the inspectors did not note any adverse

consequences. The inspectors concluded that 1BVS XPT-5 was conducted in a safe

manner.

01.5 Unit 1 Replacement Steam Generator Testina (50001)

The inspectors interviewed operations and engineering personnel, reviewed the test

procedures, and observed selected portions of Special Plant Procedure (SPP)97-048,

- "Large Load Reduction," Revision 2, SPP 97-049, "10 percent Load Decrease,"

Revision 1, and SPP 97-050, " Steam Generator Level Control Test," Revision 1. The

inspectors concluded that the replacement steam generators operated as designed and

the plant responded to the transients as expected with no significant anomalies noted. In

addition, during the replacement steam generator testing, the inspectors observed '

effective supervisory oversight of the evolutions and good coordination between

operators, system engineers, and maintenance personnel. The inspectors also noted

that the control room operators generally adhered to the Nuclear Operations Division

Operations Department Standards.

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02 Operational Status of Facilities and Equipment

O2.1 Pluaaed Unit 1 Seal Table Room Containment Floor Drain

a. Inspection Scope (71707)

On February 28,1998, the licensee changed from Mode 5 (Cold Shutdown) to Mode 4

(Hot Shutdown) with an inoperable containment floor drain. The inspectors interviewed

engineering management and the root cause investigator. The inspectors reviewed the

following documents' '

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• Work Request (WR) 970107702, " Equipment Drain Has Debris In it - CV System

Drain Bowl"

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Operability Assessment 98-019

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• Problem identification Forms (PIFs) B1998-00723, B1998-00977, and

B1998-01046

- Temporary Alteration 98-1-017, " Seal Table Room Floor Drains"

- On-Site Review Report 98-040, " Unit 1 Regen Heat Exchanger and Excess

Letdown Heat Exchanger Rooms Floor Drains Not Hydrolyzed during B1R08"

- Licensee Event Report (LER) 50-454-98004, " Reactor Coolant Leak Detection

System inopercble due to inadequate Communication"

b. Observations and Findinas

On March 15,1997, the licensee identified that the Unit 2 containment floor drain system

was plugged and inoperable. The licensee submitted LER 50-455/97001 and the issue

was documented in NRC Inspection Report No. 50-454/97005(DRP);

50-455/97005(DRP). As a result, a predecisional enforcement conference was

conducted on June 21,1997. In response to this issue, the licensee committed to

cleaning the containment floor drain system at the end of the next refueling outage on

both units.

At the request of the system engineer, mechanical maintenance personnel prepared

WR 970032868-01 to clean and inspect containment floor drains. On February 10,1998,

mechanics notified system engineering personnel that ffie Unit 1 seal table room floor

drain was plugged and that attempts to clear it had been unsuccessful. Maintenance

personnel closed the WR and initiated a PIF. However, the PIF identified several

unrelated discrepancies and was not clear that the seal table room floor drain was

- plugged and was unable to be cleared. Based on the problem description and the

immediate action taken identified in the PlF, the operators concluded that the system was

operable and the licensee's PlF screening committee agreed with the operators. No

initial action was taken. The inspectors found that a poor problem description on

PlF B1998-00723 contributed significantly to the licensee's failure to recognize that the

seal table room floor drain was plugged.

The system enginear assumed that the corrective action process would resolve the

plugged floor drain and did not take any action. However, the PlF was closed without any

corrective actions and the system engineer was not aware that corrective actions were

not in place or planned until February 27,1998. During routine PIF reviews by system

engineering personnel, and subsequent document research, the floor drain system

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engineer identified that the seal table room floor drain remained plugged. As a result, the

system engineer prepared an action request. However, the action request was

erroneously written as nonsafety-related and non-TS equipment. Therefore, the licensee

did not identify the significance of the plugged floor drain during initial reviews.

Consequently, the licensee did not recognize the significance of the plugged floor drain

untii February 28,1998, the day after changing to operational Mode 4.

As immediate corrective action, the licensee installed a temporary alteration in an existing

clean out port of the seal table room floor drain. The temporary alteration restored the J

floor drain system to operable status. The inspectors observed the temporary alteration

and considered it acceptable. At the end of the inspection period, the licensee was

evaluating long term corrective action for the plugged floor drain.

During the licensee's investigation for the associated LER 98-004, the licensee identified

that the work scope for WR 970032868-01 was not complete; specifically, clear direction

for which containment floor drains were to be cleaned was not provided. The licensee

concluded that work activities were not well documented on the completed WR. The I

inspectors' discussions with the root cause investigator indicated that the WR developed

for the floor drain cleaning had been an existing generic floor drain WR and the systc,m

engineer had given maintenance personnel marked-up drawings of the containment

building instead of a list of floor drains to clean. Both the licensee and the inspectors

concluded that WR 970032868-01 was not adequately revised to ensure all drains were

cleaned and inspected.

Technical Specification 3.4.6.1.b required that the containment floor drain and reactor

cavity flow monitoring systems be operable in Modes 1,2,3, and 4. The inspectors

noted that TS 3.0.4 required that entry into an operational mode shall not be made when i

tne conditions for the Limiting Condition for Operation (LCO) are not met and the

associated action required a shutdown if they are not met within a specified time interval.

The action requirement for TS 3.4.6.1.b stated that with the required leakage detection l

systems inoperable, restore to operable status within 7 days; otherwise, be in at least hot  !

standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Therefore, the inspectors concluded that TS 3.0.4 was i

applicable.

The failure to meet the conditions specified in TS 3.4.6.1 when Unit 1 changed

operational modes from Mode 5 to Mode 4 on February 27,1998, is considered a

violation of TS 3.0.4 as described in the attached Notice of Violation. This violation is

being cited since it could have been prevented by effective corrective action to the

. March 1997 event or the PIF documenting the condition on February 12,1998,

(50-454/98009-01(DRP)).

After the seal table room floor drain issue was identified, the licensee reviewed the scope

of the original floor drain cleaning plan and identified that the floor drains for the

regenerative heat exchanger and excess letdown heat exchanger rooms were not

inspected as committed to during the predecisional enforcement conference. The

licensee concluded and documented in On-Site Review Report 98-040 that the two heat

exchanger room floor drains were operable based on the following: (1) the rooms were

High Radiation Areas and access to the rooms was very limited; (2) floor openings exist

in the heat exchanger rooms that would allow any water to flow out of the rooms to the

elevations below and be identified through a different floor drain if a floor drain in the

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room was plugged; (3) and a search of the work history on the heat exchanger room floor

drains did not identify any previous work, which would indicate that the drains had a

history of problems. The licensee concluded that there was no reason to believe that the

floor drains were incapable of collecting water for leak identification and planned a future

evaluation to determine the appropriate scope of future actions for the floor drains in the

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heat exchanger rooms. The inspectors also concluded that the failure to provide a clear

scope list in WR 970032868-01, as described above, also contributed directly to the

l licensee failing to clear and inspect the floor drains in the regenerative heat exchanger

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and excess letdown heat exchanger rooms.

c. Conclusions

The inspectors concluded that the entry of Unit 1 into Mode 4 (Hot Shutdown) from

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Mode 5 (Cold Shutdown) with the seal table room floor drain plugged was a violation of

Technical Specifications and should have been prevented by corrective actions from

previously identified issues with the floor drain system. The inspectors concluded that

significant contributions to not recognizing the inoperable seal table floor drain were poor

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maintenance work request content and documentation, poor problem description on the

l problem identification form, and poor followup by the system engineer's when notified by

mechanics that the floor drains remained plugged. A violation was cited.

03 Operations Procedures and Documentation

O3.1 Maintenance of Senior Reactor Operator (SRO) Active Licenses

a. Inspection Scope (71707)

The inspectors reviewed the licensee's process for maintaining SRO (SRO) licenses

active. The inspectors interviewed operations and training department management and

reviewed the following procedures:

• Byron Administrative Procedure (BAP) 320-1, " Shift Manning," Revision 7

- Byron Operating Surveillance (BOS) LIC-1, "NRC Active License Tracking,"

Revision 2

- BAP 350-1, " Operating Logs and Records," Revision 14

- Operations Policy Memo 400-12 " Operators' License Information," Revision 68

' * BOS LIC-1 documentation for the fourth quarter of 1997

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b. Observations and Findinas

The inspectors reviewed BOS LIC-1 and concluded that the requirements of

10 CFR Part 55 for maintaining operator licenses active were accurately translated.  ;

However, the inspectors also noted that operations department management had issued  !

an Operations Policy Memo which provided additional guidance to the operators. This

policy allowed shift supervisor and administrative shift supervisor duties to be credited

toward maintaining an active license, contrary to 10 CFR Part 55 and BOS LIC-1.

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However, the inspectors also noted that operations management expected shift

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Supervisor as required by BOS LIC-1. With one exception noted below, the shift

supervisors and administrative shift supervisors maintained their licenses active during

the fourth quarter of 1997.

During the review, the inspectors noted that one SRO had taken credit for administrative

shift supervisor duties to meet the requirements of BOS LIC-1 for the fourth quarter of

1997, in accordance with the Operations Policy Memo. The inspectors noted that the

BOS LIC-1 dated December 31,1997, indicated that this SRO maintained an active

SRO license but would not be considered for routine assignment as a Unit Supervisor.

As a result of the inspectors questions, the licensee determined the individual's license

was inactive. The inspectors also noted the individual had not assumed duties as a Unit

Superviso. since December 31,1997; therefore, no violation of regulatory requirements '

was identified. At the end of the inspection period, the licensee was continuing to

investigate the issue.

In addition, the inspectors had difficulty independently verifying which SROs and ROs

were responsible for specific shift positions. Although shift tumover sheets and control

room door security records confirmed that TS minimum manning requirements were met,

the inspectors noted that several log entries for shift personnel did not meet the licensee

management's expectations.

c. Conclusion

The inspectors concluded that the licensee's process for maintaining senior reactor

operator licenses active was weak, in that, an Operations Policy Memo allowed credit for 4

proficiency to be taken for shift supervisor and administrative shift supervisor positions I

contrary to the requirements of 10 CFR Part SS and the licensee's operating surveillance

test. However, no violations of regulatory requirements were identified because all senior

reactor operators that conducted licensed duties during the quarter met the requirements

of 10 CFR Part 55 and the licensee's operating surveillance procedure. The inspectors

also concluded that several log entries for shift personnel did not meet the licensee

management's expectations.

03.2 Inadeauste Control Room Ventilation System Operatina Proc +'"5

a. Inspection Scope (71707)

The inspectors reviewed Byron Operating Procedure (BOP) VC-2, " Shutdown of Control

Room HVAC [ Heating, Ventilation, and Air Conditioning) System," Revision 2, and

interviewed operators and procedure writers,

b. Observations a,1d Findinos ,

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On March 11,1998, during follow-up inspection activities into a four hour non-emergency l

report in accordance with 10 CFR Part 50.72(b)(2)(iii)(D), which the licensee l

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subsequently retracted on March 12,1998, the inspectors identified that BOP VC-2 was

incomplete as written. Specifically, the procedure did not provide direction to secure the

main control room supply, retum, or make-up air filter fans or provide appropriate

guidance to verify damper positions when the control room ventilation system was l

secured from the main control room. The inspectors noted that the licensee had revised 1

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BOP VC-2 on January 7,1998, in support of a modification which relocated controls for ]

one control room ventilation train. In response to the inspectors questions, the licensee

determined that approximately two pages of the procedure had been inadvertently deleted {

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during the revision which had not been identified during the review process. The failure

of BOP VC-2 to provide appropriate guidance to shutdown the control room ventilation {'

system from the main control room is considered an example of a violation of

10 CFR Part 50, Appendix B, Criterion V (50-454/455-98009-02a(DRP)).

Furthermore, the inspectors noted that the licensee had performed BOP VC-2 at least

eight times between January 7 and March 11,1998, and had not initiated a procedure

revision. Nuclear Operations Division Operations Department Standards, Section Vill,

" Procedural Adherence," specifies, in part, that when using operating procedures a

method of placekeeping shall be used. The standards also specify that when an

individual perceives that any procedure is technically incorrect the following actions are to

be taken: (1) stop and ensure the system is in a safe condition; (2) inform supervision of

the situation; and (3) the supervisor shall evaluate the situation and determine if the

procedure can be performed as written, otherwise the procedure shall be revised prior to

continuing the activity. The inspectors noted that if the procedure adherence standards

were implemented, the operators could not shutdown the control room ventilation system

from the main control room in accordance with BOP VC-2 without revising the procedure.

c. Conclusions

The inspectors concluded that the licensee's process for maintaining senior reactor

operator licenses active was weak, in that, an Operations Policy Memo allowed credit for

proficiency to be taken for shift supervisor and administrative shift supervisor positions

contrary to the requirements of 10 CFR Part 55 and the licensee's operating surveillance i

test. However, no violations of regulatory requirements were identified because all senior j

reactor operators that conducted licensed duties during the quarter met the requirements .

of 10 CFR Part 55 and the licensee's operating surveillance procedure. The inspectors  !

also concluded that several log entries for shift personnel did not meet the licensee

management's expectations. l

08 Miscellaneous Operations issues l

08.1 10 CFR Part 50.54m Letter Commitment Review

a. Inspection Scood2%S

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The inspector 4 reviewed th3 status of commitments pertaining to Byron's March 28,

1997, response to the NRC's request for information pursuant to 10 CFR 50.54(f). The

commitment numbers correspond to those used by the licensee in their March 28,1997, l

response.

b. Observations and Findinas

Commitment 95: "As described in Section 4.7.4 below, we are also taking special

measures to assess and monitor our performance to ensure that areas of weakness

indicated by the LaSalle and Zion operational events are not present or are addressed at

all of our nuclear stations." The measures referred to included: (1) the development of

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Operations Department indicators; (2) the NOD [ Nuclear Operating Division) Vice

President of Nuclear Support (who headed the investigation of the Zion event) would visit

each site to observe and review control room activities; and (3) operations peer

assessments to evaluate safety culture, conservatism of operational decision making,

and implementation of operations standards.

The inspectors reviewed the licensee's operations department indicators and noted that

the indicators were current. The inspectors also noted that the licensee had recently

identified an adverse trend in out-of-service errors as a result of monitoring these

indicators. In addition, the inspectors noted that the NOD Vice President of Nuclear

Support, the Dresden Station Vice President, and an operation peer group had visited the

site, observed control rcom activities, and evaluated the safety culture and operations

standards. As part of each of the above site visits, the evaluators provided improvement

comments to the licensee.

c. Conclusions

The inspectors concluded that the licensee was meeting commitment 95. This item is

closed.

08.2 10 CFR Part 50.54(f) Performance Indicators

a. Inspection Scope (92901)

The inspectors reviewed the development of selected 50.54(f) performance indicators

and interviewed operations, engineering, and quality and safety assessment personnel.

b. Observations and Findinas

The inspectors reviewed the following performance indicators:

1.1 Automatic Scrams (Reactor Trios) While Critical

The licensee developed performance indicator 1.1 based on the number of unplanned

reactor trips (trips) per year while critical. Examples include trips from unplanned l

transients, equipment failures, spurious signals, or human error. Trips occurring during

the execution of procedures in which there was a high chance of a trip occurring, but the

occurrence of a trip was not planned, are included. Since February 1997, Byron Station

- has had only one unplanned automatic trip while critical (October 1997), which was less

than the action threshold of more than one trip per unit per year. However, during the

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Unit i startup in March 1998, the reactor was manually tripped on two separate

occasions, neither of which were counted against this performance indicator since they

were not automatic and the reactor was not yet critical. The first of these manual trips

occurred on March 6,1998, during the performance of rod drop testing, the operators

tripped the reactor as a result of losing communication with the field operators

participating in the testing. The second, on March 7,1998, during the aborted Unit 1

startup, the operators manually tripped the reactor due to being unable to fully insert the

control Bank "C" rods.

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! 12 Safety System Actuations

The licensee developed performance indicator 12 based on the number of manual or

automatic actuations of the logic or equipment of either certain emergency core cooling

systems (ECCS) or, in response to an actuallow voltage on a vital bus, the emergency

AC power system. Regarding the ECCS, only actuations of the high pressure injection

system, low pressure injection system, or safety injection tanks were counted. Actuations

of the emergency AC power systems were counted only if the emergency AC power

system's output breaker closed, or should have closed, to power a dead bus. Since

February 1997, Byron Station has had zero safety system actuations, which was less

than the action threshold of more than one safety system actuation per unit per year. The

performance indicator was derived from events that were reportable in accordance with

10 CFR Parts 50.72 and 50.73. However, the inspectors noted that this performance

indicator did not include all of the possibilities of safety system actuations that were

reportable such as radiation activated ventilation actuations or containment isolations.

l

C16 Number of Problem Identification Forms Written

The licensee developed performance indicator C16 based on the number of PlFs written l

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at each site. Since March 1997, Byron Station has exceeded the action threshold of less

than 160 PIFs written per month. Consequently, the licensee has concluded that the

station's threshold for problem identification was sufficient to support the corrective action

program.

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c. Conclusions

The inspectors concluded thct the performance indicators li,12, and C16 indicated that

the licensee's performance in each area was satisfactory.  !

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08.3 (Closed) Inspector Follow-up item (50-454/455-95003-01(DRP)) (92901): "RCS [ Reactor

Coolant System] Pressure Transient Required the Shutdown of the 2D RCP [ Reactor

Coolant Pump)." The initial review found that the licensee acted properly in response to

the transient; however, the issue remained open pending inspector review of the

licensees root cause analysis. The inspectors noted that the licensee's actions included i

stabilizing the plant and restoring pressure, revision of Procedures 1/2BVS 4.6.2.2-1, j

" Unit % Reactor Coolant System Pressure Isolation Valve and Cold Leg injection Isolation  !

Valve Leakage Surveillance," to require that this portion of the test be done with a

pressurizer bubble, and counseling system engineers on better. communications which

- could have prevented the event. The inspectors reviewed the root cause report and the i

modified procedures and concluded that the licensee's actions were acceptable. This  :

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item is closed.

08.4 (Closed) Violation (50-454/455-96012-05(DRP)) (92901): " Failure to Follosy a Procedure

for a Degraded Containment Floor Drain Monitoring System." The licensee confirmed

that the containment floor drain recorder,1RF008, should have been entered in the  !

Degraded Equipment Log (DEL). Short term corrective action was to enter the affected j

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recorder in the DEL. In order to reaffirm the purpose of the DEL, the licensee discussed

the history, intent and purpose of the DEL in a supervisors meeting. The inspector j

reviewed BAP 390-13, " Degraded Equipment Program," to check for any notable 1

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weaknesses. None were identified and the corrective actions were found to be

acceptable. This violation is closed.

i 08.5 (Closed) LER 50-454/98004 (92700h " Reactor Coolant Leak Detection System

inoperable due to inadequate Communication." T his issue is discussed in detail in

Section O2.1. The inspectors considered LER 454/98-04 very good. The report was

critical and comprehensive. Corrective actions appeared strong. The licensee's

corrective actions will be reviewed during the inspectors review of the licensee response

to the violation will be cited in Section O2.1. The inspectors considered LER 454/98-04

closed and the issue will be followed with Violation 50-454/98009-01(DRP).

II. Maintenance

M1 Conduct of Maintenance

M1.1 Maintenance Observations

a. Lnspection Scope (62707)

.

The inspectors observed the performance of all or portions of the following work requests

l (WR). When applicable, the inspectors also leviewed TSs and the Updated Final Safety

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Analysis Report (UFSAR).

• WR 980024198-01 Bank A Insertion Limits Rod Position Annunciator 1-10-806

is in Alarm and Should Not Be

. WR 980018826-01 Replace Valve (2SI 89568) Intemals Due to Failed Leak

Test

.

WR 970016380-02 Replace Damaged Piping on the 28 Essential Service

Water Pump (SX) Discharge Strainer Back Wash Line

• WR 970040570 Replace the Nuclear Loop Power Supply Card on the 2A

Steam Generator Loop

WR 980026819 Remove Lagging on Discharge of CV Pump to Support -

Ultrasonic Testing

b. Observations and Findinas

Safety iniection Accumulator B Outlet Check Valve Repair

.

The inspectors observed portions of the testing and maintenance of safety injection

accumulator B outlet Check Valve 1818956B. The valve failed the initial surveillance test.

Mechanics repaired the check valve and retumed the check valve to service after

completing a " blue check" satisfactorily However, the valve failed the leak check a

second time. The licensee reviewed actions taken during the first repair effort with  !

non-station personnel who identified that a standard blue check could give false results  ;

for this particular type check valve. Additional acceptance criteria for blue ?, hecks and l

other seat flatness tests were used to ensure the valve would not leak. After the second

repair and verification,1S189568 did not leak and was retumed to service. Mechanical

maintenancc personnel conducted a critique after the second repair effort to document j

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lessons leamed and incorporate the necessary steps into future WR instructions. The

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inspectors concluded that initially, the licensee did not have the necessary expertise to

satisfactorily repair 1Sl8956B.

c. Conclusions

,

The inspectors concluded that each of the observed maintenance activities satisfied the

regulatory requirements. The inspectors also noted that based on the failure to conduct

an appropriate blue check and the additional seat flatness tests required to ensure a

correct seating surface, the licensee did not initially have the necessary expertise to

satisfactorily repair safety injection check valve 1S189568.

M1.2 Surveillance Test Observations

a. Inspection Scope (61726)

The inspectors interviewed operations and engineering personnel, reviewed the

completed test documentation, and observed the performance of selected portions of the

following surveillance test procedures.

. 1BOS 3.1.1-35 Unit 1 Analog Channel Operational Test of Intermediate

Range Channel N35.

. 2BOS 3.2.1-970 ESFAS Instrumentation Slave Relay Surveillance. (Train B

Autc:natic Valve Actuation on Refueling Water Storage

Tank Lo-2 Level (K 648)).

. OBOS 3.2.1-990 ESFAS Instrumentation Slave Relay Surveillance (Train B

Feedwater isolation)

. BIS 3.1.1-203 Surveillance Calibration of Steam Generator Narrow Range

Level Protection Loop

. 1BOS 5.2.b-1 ECCS Wating and Valve Alignment Monthly Surveillance

. 1BOS 8.1.1.2.A-2 1B Diesel Generator Monthly Operability Surveillance l

c. Conclusion

1

The inspectors concluded that each of the observed surveillance tests satisfied the

regulatory requirements and all of the components tested were operable. The inspectors

also noted that the material condition of the tested components was generally good.

However, the inspectors identified several minor deficiencies on the 18 diesel generator

(e.g., oil and water leaks, missing ventilation gasket, and inadequate thread engagement

- on a relief valve) which the licensee subsequently addressed by initiating corrective

maintenance WRs.

M3 Maintenance Procedures and Documentation

M3.1 Maintenance Control of WRs

a. Inspection Scope (62707)

During routine maintenance observations, the inspectors noted a mechanic working on an

essential service water (SX) pump, performing a task that had been authorized

approximately 14 months prior to the inspectors' review. The inspectors noted that the

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authorizing signature on the work package had been deleted. The inspectors questioned

the licensee's program from the standpoint of controlling and authorizing WRs that had

previously been authorized but then placed on hold.

b. Observations and Findinas

I

During a review of WR 960100631, the inspector noted that electrical maintenance

personnel began removing the lube 1B-SX oil pump motor without authorization from the

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control room. The authorizing SRO's signature had been previously lined-out. Byron

Administrative Procedure (BAP) 1600-1, " Action / Work Request Processing Procedure,"

Revision 41, Section D, Paragraph 5, stated that an SRO shall authorize work to start,

and Section D, Paragraph 6, stated that the lead worker was to verify that the authorizing

signature was obtained on the WR prior to starting work. The WR was originally

authorized in December 30,1996, and then not performed as originally scheduled. The

authorizing signature was lined out the same day that the WR was originally scheduled.

The inspectors considered that the actual safety significance of the unauthorized WR was

minimal. The work had been scheduled and the SRO immediately authorized the work

after the issue was noted by the inspectors. The unauthorized work activities did not

create a personnel hazard and did not remove any operable safety-related equipment

from service. In addition, the inspectors had not identified any previous occasions of

working without appropriate authorization. Therefore, the inspectors concluded that the

failure to obtain the authorizing signature on the WR prior to starting work in accordance

with BAP 1600-1 was a violation of minor significance and is being treated as a Non-Cited

Violation, consistent with Section IV of the NRC Enforcement Policy

(50-454/98009-03(DRP)).

The inspectors' procedural reviews and interviews with licensee personnel identified that  !

the work control process, as defined in BAP 1600-1, did not have steps to place a WR on

. hold, with the intention of later rescheduling the work activities. Generally, the

maintenance managers' expectations were that a WR was scheduled and controlled

using the scheduling process. However, no expectations or requirements existed to

control the signature page authorization to place a WR on hold and restart the work '

activity at a later date.

After being questioned by the inspectors, the licensee identified approximately 50 out of

160 WRs on hold in the maintenance department that still had authorized SRO

signatures. The inspectors were concemed that the plant conditions may not be

appropriate for the WRs and therefore, the SRO's work authorization signature should

- have been removed.  ;

Title 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"

required, in part, that activities affecting quality shall be of a type appropriate to the

circumstances. The inspectors concluded that the failure to have established a written

procedure for the control of WRs while the WRs were on hold, was an example of a

violation of 10 CFR Part 50, Appendix B, Criterion V (50-454/455-98009-02b(DRP)).

At the end of the inspection period the licensee was in the process of revising

BAP 16001 to control WRs on hold. The licensee had also removed the signature pages

from the 50 WRs on hold that had contained the authorizing SRO signatures.

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c. Conclusions

The inspectors noted that generally, WRs were adequately controlled and scheduled.

However, the inspectors identified one example whace work was being accomplished

without proper SRO authorization. Also, approximately 50 WRs had SRO authorizations,

but the work activities were not on the current schedule, and were considered on " hold."

The inspectors concluded that Byren Administrative Procedure (BAP) 1600-1 was

inadequate in that it did not provide guidance on how to process a WR that had been

authorized by an SRO, and then the work activity had been put on " hold" for an extended

period of time. A violation was issued.

M8 Miscellaneous Maintenance issues

M8.1 (Closed) Violation (50-454/455-96012-03a(DRP)) (92902): " inadequate Corrective Action

for Heat Exchanger Assembly." The inspector reviewed the licenses corrective actions

which included coaching of the mechanical maintenance personnelinvolved in the event

on attention-to-detail and procedure adherence. The inspector also reviewed the

licensees root cause investigation and found it acceptable. This portion of the violation is

closed. It should also be noted that the second portion of this violation,

(50-454/455-96012-03b(DRP)), was previously closed and documented in NRC

Inspection Report No. 50-454/97018(DRP); 50-455/97018(DRP). Thus the entire

violation (50-454/455-96012-03(DRP)) is closed.

Ill. Enaineerina

E3 Engineering Procedures and Documentation

E3.1 Failure to Update the Uodated Final Safety Analysis Report (37551)

The inspectors walked down portions of the containment purge system while it was

operating. The inspectors reviewed safety evaluation T1-93-0152, completed on

October 16,1993, which documented a change to the operating procedure of the

containment purge system during refueling operations. The safety evaluation specified

that the containment mini-purge system would be in operation during refueling activities

and the main containment purge system would be secured. The UFSAR,

Section 15.7.4.2.2.3 indicated that during refueling operations, the containment purge

system was to be in operation and providing at least 50 feet per minute (fpm) air flow

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across the refueling cavity surface. The safety evaluation did not discuss the technical

basis for the acceptability of lower transport times associated with the decreased flow

provided by the containment mini-purge system.

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ln addition, the safety evaluation stated that a change to the UFSAR was required;

however, the licensee did not submit the required revision to the UFSAR in

December 1994 or December 1996. The UFSAR change was then scheduled for

submittal in December 1998, but was subsequently canceled. At the end of the

inspection period, the licensee was still investigating the technical basis for the

acceptability of the lower transport times associated with the operation of the containment

mini-purge system and the basis for the failure to update the UFSAR. This issue is

considered an Unresolved item (50-454/455-98009-04(DRP)) pending NRC review of the

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licensee's technical basis for the acceptability of the containment mini-purge system and

the causes for the failure to update the UFSAR.

IV. Plant Support

R1 Radiological Protection and Chemistry (RP&C) Controls

R1.1 Radioloalcal Postinas

1

i a. Inspection Scope (71750)

!

The inspectors routinely observed the status and posting of radiologically controlled areas

(e.g., radiologically posted areas, radiation areas, radiologically contaminated areas).

The inspectors interviewed operators and radiation protection personnel and reviewed

Byron Radiological Protection Procedure (BRP) 5010-1, " Radiological Posting and I

Labeling Requirements," Revision 15.

b. Observations and Findinas

During an inspection in the auxiliary building on March 9,1998, the inspectors noted a '

step-off pad and radiological waste .eceptacle within the 1 A SI pump cubicle adjacent to

the entrance. The inspectors noted radiological rope boundaries established with two

" CAUTION CONTAMINATED AREA" signs along two of three accessible sides of the

area. In the location where the step-off pad and radiological waste receptacle were

located, the inspectors did not identify any radiological tape, rope or " CAUTION

l CONTAMINATED AREA" sign present, leaving approximately a seven foot opening in the

contamination area boundary unposted. The two signs that had been posted could not

be read from the unposted side. The inspectors noted that BRP 5010-1, Paragraph F.3,

stated that any radiologically posted area shall be conspicuously posted so as to wam

personnel approaching the area from any direction. This problem was exacerbated by

the fact that the unposted area was immediately adjacent to the pump cubicle entrance.

In response to the inspectors concems, the shift manager had the posting immediately

corrected.

Technical Specification 6.8.1.a required that written procedures be established,

implemented and maintained for procedures recommended in Appendix A, of Regulatory '

Guide 1.33. Appendix A of Regulatory Guide 1.33, specified contamination control as an

~

example of a radiation protection procedure. The failure to post the contamination area

within the 1 A Si pump cubicle in accordance with BRP 5010-1 was a violation of ,

TS 6.8.1.a (50-454/98009-05(DRP)), as described in the attached Notice of Violation.

c. Conclusions

The inspectors concluded that the licensee failed to post a contamination area in

accordance with radiological protection procedure Byron Radiological Protection

Procedure 5010-1.

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V. Manaaement Meetinas

X1 Exit Meeting Summary

l

The inspectors presented the inspection results to members of licensee management at

the conclusion of the inspection on April 6,1998. The licensee acknowledged the

i findings presented. The inspectors asked the licensee whether any materials examined

l during the inspection should be considered proprietary. No proprietary information was ,

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identified.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

' K Graesser, Site Vice-President

K Kofron, Byron Station Manager

J. Bauer, Health Physics Supervisor

D. Brindle, Regulatory Assurance Supervisor

E. Campbell, Maintenance Superintendent

T. Gierich, Operations Manager

.T. Schuster, Manager of Quality & Safety Assessment

M. Snow, Work Control Superintendent

B. Kouba, Engineering Manager

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INSPECTION PROCEDURES USED  !

IP 50001: Steam Generator Replacement inspection l

lP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 37551: Engineering

IP 71750: Plant Support

IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power  !

Reactor Facilities '

lP 92901: Followup operations

1

IP 92902: Followup Maintenance 1

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ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-454/98009-01 VIO Unit i entered Mode 4 with portions of containment i

floor drain inoperable.

l

50-454/455-98009-02a VIO Inadequate procedure (BOP VC-2) for operation of )

control room ventilation

50-454/455-98009-02b VIO Failure to have established a written procedure for

the control of WRs while the WRs were on hold.

50-454/98009-03 NCV Failure to obtain authorizing signature on Work  ;

Request.

50-454/455-98009-04 URI Potential failure to submit a UFSAR revision for

containment purge operation.

50-454/455-98009-05 VIO Failure to post the contamination area in

accordance with BRP 5010-1. I

Closed  !

50-454/455-95003-01(DRP)

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IFl RCS Pressure Transient Required the Shutdown of ,

the 2D RCP

50-454/455-96012-03a(DRP) VIO Inadequate Corrective Action for Heat Exchanger

Assembly.

50-454/455-96012-05(DRP) VIO Failure to Follow a Procedure for a Degraded

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Containment Floor Drain Monitoring System. I

50-454/98004 LER Reactor Coolant Leak Detection System Inoperable

Due to inadequate Communication

50-454/98009-03(DRP) NCV Failure to obtain authorizing signature on Work

Request.

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LIST OF ACRONYMS USED

BAP Byron Administrative Procedure

BAR Byron Annunciator Response

BMP Byron Mechanical Maintenance Procedure

BOP Byron Operating Procedure

3OS Byron Operating Surveillance

i BRP Byron Radiological Protection Procedure

BVS Byron Engineering Surveillance

DEL Degraded Equipment Log

DG Diesel Generator

DRP Division of Reactor Projects l

DRS Division of Reactor Safety

ECCS Emergency Core Cooling System

l ER Engineering Request

l ESFAS Engineered Safety Feature Actuation Signal i

FME Foreign Material Exclusion l

FPM Feet per Minute l

HLA Heightened Level of Awareness l

HVAC Heating, Ventilating, and Air Conditioning

IFl inspector Follow-up item

IPSS In-Plant Shift Supervisor ,

LCO Limiting Condition for Operation I

LCOAR Limiting Conditio, for Operation Action Requirement

LER Licensee Event Report

NCV Non-cited Violation

NOD Nuclear Operating Division

NRC Nuclear Regulatory Commission

NSWP Nuclear Station Work Procedure

OOS Out-of-Service

PDR Public Document Room

PlF Problem identification Form

PPM Parts Per Million

QNE Qualified Nuclear Engineer

RCP Reactor Coolant Pump

RCS Reactor Coolant System

RH Residual Heat Removal

RP Radiological Protection

RP&C Radiological Protection and Chemistry

SI Safety injection

SM Shift Manager

SPP Special Plant Procedure

SRO Senior Reactor Operator

SX Essential Service Water System

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

US Unit Supervisor

VIO Violation

WR Work Request 22