ML20198T507

Insp Repts 50-254/97-26 & 50-265/97-26 on 971103-1223. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20198T507
Person / Time
Site:	Quad Cities
Issue date:	01/21/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20198T488	List: IR 07100103/2012023 ML20198T481 ML20198T507
References
50-254-97-26, 50-265-97-26, NUDOCS 9801270078
Download: ML20198T507 (30)

See also: IR 05000254/1997026

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U. S. NUCLEAR REGULATORY COMMISSION

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REGION 111

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Docket Nos:

50 254,50 265

Licsnse Nos:

DPR-29, DPR-30

Report No:

50-254/97026(DRP); 50 265/97026(DRP)

Licensee:

Commonwealth Edison Company (Comed)

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Facility;

Quad Cities Nuclear Power Station, Units 1 and 2

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Location:

22710 206tri Avenue North

Cordova, IL 61242

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Dates:

November 3 - December 23,1997

Inspectors:

C. Miller, Senior Resident inspector

K Walton, Resident inspector

L. Collins, Resident inspector

K Lambert, Radiation Spedalist

R. Ganser, Illinois Department of Nuclear Safety

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Approved by:

Mark Ring, Chief

Reactor Projects Branch 1

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EXECUTIVE SUMMARY--

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Quad Cities Nuclear Power Station, Units 1 and 2 '

NRC inspection Report No. 50 254/97026(DRP); 50-265/97026(DRP)

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iThis inspection included aspeds of licensee operations, engineering. maintenance, and plant--

support. The report covers a 6 week period of resident inspection. .

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Qasations

Equipment issues challenged opemtors who responded appropriately. However, in a , .

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number of cases, longer term corrective actions to fix thu equipment issues had not been

completed (Section 01.1).

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Non-licensed equipment operators generally completed required surveillances

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adequately. The inspectors noted one inappropriete entry of "N/A" (not applicable) for

. diesel generator room temperature on a required surveillance and also identified one

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- weakness in operator awareness of the status of the shared 250 Volt direct current (Vdc) .

battery charger (Section 01.2).-

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The inspectors noted a weakness in the equipment operator surveillance procedure in -

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-- that the procedure did not include checks of the pumps required for the interim altemate

-safe shutdown method (IASM) (Section 01.2).

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Transition to the electronic out of service (EOOS) progmm was smaoth and effective.

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Self-assessment of the OOS program was aggressive and consistent whh the

performance expectations of operations management (Section 01.4).

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Until prompted by the inspectors, operations management was not aware of the adverse

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trend in unidentified leakage in the Unit i drywell. The inspectors concluded the

evaluation of the leak was in compliance with Technical Specifications (TSs) and allowed

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by the. Code (Section 02.1).

The inspectors concluded the licensee implemented administrative changes to the

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corrective action program (CAP) as committed in a 50.54(f) letter (Section 07.1).

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The establishment of root cause experts and investigators appeared to be a good

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initiative ~ However, the inspectors found that root cause evaluation (RCE) investigators

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were being pulled away from their assigned duties to perform other functions

(Section 07.1).

The quality and safety assessment group continued to identify corrective action program

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- issues, some of which were previously identified as a weakness. Similarly, the inspectors -

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noted specific issues of weak corrective actions in this and previous inspection reports

where corrective actions did not prevent recurrence. The inspectors concluded the =

effectiveness of the new CAP to ensure that corrective actions were in place to prevent

recurrence of previously identified deficiencies had not yet been demonstrated - '

'(Section 07.1).

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Maintenance

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Some maintenance activities were not well coordinated with the i.perations department to

mhimize abnormal system lineups (feedwater control). One safety-related system

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problem (control rod drive) was not repaired or tracked in a corrective action system _

(Section M1.1).

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Two instances involving valve reassembly errors by contracted maintenance personnel

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were not detected prior to retuming the unit to power operations, whitti resuKed in a

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procedure violation, in addition, proposed corrective actions did not appear to be

effective to ensure similar problems would not recur (Section M1.3).

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- Corrective actions to identified 4 kV breaker problems in 1996 and 1997 remained

incomplete at the end of the inspection period.- A number of safety-related breakers had

not been refurt>ished in more than 28 years. Vendor recommended rnaintenance tasks

for GE 4 kV breakers were not being performed.

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Recommended preventive maintenance tasks were not identified or performed for sorn:

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plant equipment modifications, including the station blackout diesel generators and tht.

. Merlin-Gerin 4 kV breakers that were insts!Ied more than 2 years ago.

The station identified examples of a violatinn involving missed TS required surveillances.

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A root cause evoluation was performed to address previous TS noncompliances.

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Howwver, only one of three of the new issues was identified as a result of corrective

actions from the root cause evaluation (Section M1.4).

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- Two maintenance activities observed' indicated a lack of appropriate caution on the part

- of the workers performing critical rigging tasks at the point where there was increased

potential for equipment d:;uage (Section M1.5).

Enoineerino

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The technical enginee@g approach to resolve the emerging 10 CFR Part 50,

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Appendix R, safe shutdown issues was good. That is, the decision to simplify the method

= and reconstruct the design and licensing basis was appropriate. However, the NRC

continued to have concems regarding the process for changing the licensing basis,

- implementing new procedures, and establishing the operability of the new safe shutdown

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method (Section E1.3).

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The standby liquid control (SBLC) pumps periodically failed the in-service test (IST) due

to low indicated flow. - A long term solution to replace the flowmeters had been delayed

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. due to higher priority engineering work (Section E2.1).

. Plant. Support

A' violation of NRC requirements was identi%d for an individual entering a high radiation

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area (HRA) while signed onto a radiation work permit (RWP) that did not authorize

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. access to HRAs. However, the individual's radiation exposure for the entry was small.

This violation was treated as a Non-Cited Violation due to licensee identification and

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offective corrective actions, which included posting a greater at the entrance to the

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radiologicalY protected area and initiating the high radiation access ticket program

(Section R1.1).

The inspectors concluded the 10 CFR Part 50, Appendix R, safe shutdown prudure

training of ths crew of operators was good. Initially, the Quad Cities Appendix R

Procedures (QCARPs) were not adequate to ensure specific actions were completed

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within the time required. After revising the procedure, operators demonstrated the ability

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to execute the QCARPs in a timely manner. The inspectors identified walkways were not

adequately lit in accordance with Appendix R requirements (Section F1.1).

The inspectors concluded the emergency drit! successfully demonstrated the licensee's

capabilities to implement the emergency plans and procedures. Offsite notifications and

activation of the Technical Support Center were within time limits. Control room

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performance was good (Section P1.1).

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summary of Plant status

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UnN 1 was at full rmer at the beginning of the inspection period. Th wit reduced power on

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November 8 through November 11,1997, while operators performed drywell leak inspections and

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located a leak on a core sprey system vent valve Following tNs, the unN was retumed to full

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power but was subsequently shutdown on December 20 due to problems with the 10 CFR

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Part 60, Appendix R, safe shutdown analysis and procedures.

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Unit 2 remained in cold shutdown throughout the inspection period due to unresolved issues

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concoming 10 CFR Part 60, Appendix R, safe shutdown analysis and procedures.

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L,poerations

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Conduct of Operations -

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General Comments (71707) .

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During the inspection period, numerous equipment issues challenged operators and

several tienes required entry into limiting condition for operation (LCO) action statements.

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Operators responded appropriately in the short term. However, in some cases the longer

term corrective action to fix the undertying root cause of the equipment issues had not

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been completed. Therefore, the potential existed for the same challenges to ,ecur or for

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existing deficient conditions to continue to degrade. For example, Unit i experienced

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increased reactor coolant system leakage requiring a power reduction and drywell entry to

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locate the source of the leakage (Section 02.1). Continued problems with the tuttnne

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gland seal exhausters and condenser level control valves required manual operation by

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operators in a high radiation area. Unit 1 chemistry parameters (conductivity and

chlorides) increased, but did not approach TS limits, due to a condenser tube leak which

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required increased monitoring by both the Chemistry and Operations departments. Unit 1

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- enterort T8 acXn statemenu twice in the inspection period due to equipment problems

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-' with the drywell equipment drain sump pump logic (failed relay) and the drywell floor drain

sump flow integrator (biown fuse)' During testing the 3E automatic depressurization

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system valve failed to open.

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Although Unit 2 was shut down throughout the inspection period, equipment problems

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regulating transformer resulted in a low voltage condition on a reactor protection system

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bus. The condition caused a trip of the electrical protection assembly which resulted in

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partial Group ll and lli primary containment isolations and a loss of shutdown cooling.

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Operators followed abnormet procedures and restored the reactor water cleanup system

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in the decay heat removal n? ode within i hour. On another occasion, a sluggish low flow

feedweter regulating valve resulted in decreasing water level which was promptly caught

and corrected by Unit 2 operatorst

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DThese examples demonstrated prompt and appropriate operator actions which are

characteristics of good operator performance, However,it,spections revealed some

instances where conduct in the control room did not meet the expectations of licensee .

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.TC:TM for pid::'r.dem. For example, the inspec6 ors observed lloonsed

operators and supervisors engaged in normerk related conversations and using

IG-iWi language in the control room. Additional observations on the conduct of

- Operations are in Section 01.2.

01.2 Operator Rounds

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Inaceotion Scope (71707)

The inspectors accompanied UnN 1 equipment operators (EO) during plant lours (rounds)

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on three occasions and reviewed the following complettd round sheets for the 2 wook

period November 16 2g:

QOS 0005 812

• Operators' Surveillance Tumover Shoots U1 Equipment

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Q08 0005 815

" Operators' Surveillance Tumover Sheets Outside Equipment

Operator"

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operators recorded accurate readings and information and adequately performed general

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checks of assigned areas of responsibility. The inspectors identi6ed several minor

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problems with the lack of follow-up by either operatora or supervisors regarding abnormal

readings or conditions. One issue was of greater significanoe and involved the

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inappropriate use of "WA" (not applicable) on the surveillance procedure.

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Examples of minor defiolencies in recording data on the procedures included the use of

check marks rather than a recorded value, failure to provide notes or comments for

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- abnormalities during general area checks (a check mark for Technical Support Center

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[TSC) building although the air compressor was broken), and the failure to write an action

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request (AR) for longstanding out of tolerance readings (tuttiine bearing lube oil header

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pressure). Additional operator rounds deficionoles are discussed below.

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inanorocriate Use of Not Anolicable

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l During tours of the Unit 1 and shared emergency diesel generator (EDG) rooms, the

inspectors noted that room temperature readings were required to be recorded. The

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. shared EDG roon; temprature had consistently been documented but the UnN 1 EDG

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room temperature was marked *WA" on the operators' surveillance procedure. The EO -

indicated that botn the Unit 1 and Unit 2 EDG toom tempentures could not be recorded

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beoeuse no temperature gauges were installed in those rooms. The nspec ors a er

found that the procedure requirement to record this reading was added during the last

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revision of the procedure on September 22, igg 7.

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id inspectors were concemed that the procedure approval and validation process failed

- to address the method that operstors _would used to measure EDG toom temperature,

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Also, for approximately 2 months after the procedure revision, neither operators nor -

supervisors questioned the new requirement and instead happropriately recorded *WA"

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~ on the procedure.' The inspectors did not find any other inappropriate uses of "MA" on

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the completed procedures reviewed. The operations manager took actions to install

temperature gauges in the EDG rooms and remind operators via a note in the daily orders

book that the use of N/A in this context was not acceptable.

Ooerator Awareness of Eautoment Status

During rounds the inspectors observed that the shared 250 Vdc battery charger was

tagged out of service, but that it was not documented on operator tumover sheets. The

EO did not know why the battery charger was out of service (OOS). The inspectors also

asked a Unit i nuclear station operator (NSO) about the charger and found that the NSO

did not know that the charger was OOS. In fact, the charger had been OOS because of

breaker malfunctions.

On a separate occasion, the EO identified that the TSC building ventilation air

compressor was not functioning and immediately informed the unit supervisor. One of

the emergency preparedness (EP) coordinators located in the TSC told the EO that

maintenance workers had discovered the problem the previous day and had written an

AR. At the time, the inspectors observed that no AR tag was hung near the compressor.

Several days later, the inspectors checked on the status of the AR and found that it had

not been written.

In both of these cases operators were not fully aware of the current equipment status

including any actions taken via the corrective action program. The shared 250 Vdc

battery charger was not currently required by TSs since the Unit 1 battery charger was

online; however, availabihty of importrnt backup equipment for safety significant systems

such as 250 Vdc was important information for operators, in the case of the TSC air

compressor, the operator took appropriate immediate actions by contacting the unit

supervisor, but a lack of follow-through by the individuals who discovered the equipment

problem and the operating crew upon subsequent discovery resulted in broken equipment

not being entered into the corrective action program for several days. Since the broken

TSC air compressor does not affect plant safety, the issue was minor.

Interim Altemate Shutdown Method Eauipment Not included in Operator Rounds

During rounds the inspectors noted that the surveillance procedure did not require checks

of the pumps used for the interim alternate shutdown method (IASM). The IASM was a

newly it':plemented method used to shut down the reactor during an Appendix R fire in

the event all other methods failed. Given the results of the individual plant examination -

extemal events (IPEEE) and various other recently identified problems with the

Appendix R safe shutdown (SSD) procedures, the risk significance of the tASM was high.

The maintenance department performed a monthly surveillance test of the pumps.

However, the lack of daily checks by operators of this equipment, located in an open shed

exposed to the environment, was inconsistent with the licensee's standard practice to

conduct general area equipment checks for important equipment.

Operations department managers subsequently decided that some checks of the pumps

si.ould be included on operator rounds. At the end of the inspection period, the

procedure was under revision to include checks of the engine heater, battery charger

status, and general area checks.

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01.3 Conclusions on the Conduct of Operations

Numerous equipment issues challenged operators who responded appropriately;

however, longer term corrective actions to fix the underlying root cause of the problems

and prevent recurrence were not always completed. Although operator performance in

response to those issues was good, the inspectors noted some instances where conduct

in the control room did not meet the expectations of licensee management for

professionalism.

Non-licensed equipment operators generally completed required surveillances during

rounds adequately and were knowledgeable of plant equipment operation and status.

The inspectors identified one example where equipment operators inappropriately entered

• N/A" for required readings of emergency diesol generator room temperature and one

example in which operators were not aware of the status of the shared 250 Vdc battery

charger. The inspectors also noted a weakness with the operator rounds procedure in

that checks of the IASM pumps were not required.

01.4 ReyjugtpyLQLatnic.eRogrAm

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lopptchofLSpopp (71707)

The inspectors reviewed the licensee's out of service (OOS) program.

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QhmyAUQDt Pfldf.Lrglinga

The 003 program was designed to protect personnel and equipment from hazards

associated with removal of plant equipment from service for maintenance. The licensee

was in the transition from using a manual system, govemed by Quad Citie6

Administrative Procedure (QCAP) 230-04, to an electronic out of service (EOOS) system

which was computer based and part of the electronic work control system (EWCS). The

procedure goveming the EOOS was an interim corporate procedure, IP 97136, which

applied to all nuclear stations in the Comed system. The licensee plcnned to phase out

the old procedure within the next several months when all of the old OOS applications

were cleared or converted to the EOOS.

Quad Cities was the last station in the Comed system to implement the EOOS in

November 1997, There were few problems with the new EOOS system. Most of the

plant equipment had been incorporated into the system. Operators reported that initial

use e,f the new system was somewhat more complex but that the safety assurance,

syqem capability, and enhanced ease of documentaion had been an ovsrall

11provement. The initial training effort prior to tuming on the EOOS was good. Assist

pe +.sonnel were assigned 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day for a 2 week period following the initial EOOS

turn on. Sutssequent to this, assistance was available on an on call basis. One potential

problem associated with the EOOS was that continued attention to the status of systems

as they are released for retum to service was required in order to prevent equipment

important to plant safety from remaining out of service for longer periods of time than

necessary, The inspectors did not note any delays. The inspectors' review of several

OOS applications did not reveal any discrepancies.

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Self assessment efforts of the operations department included a separate category for

the 008 program. The inspectors' review of the OOS self assessment indicated that the

licensee had property identified program and performance problems.

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Conclusions

Transition to the EOOS was smooth and effective. Problems were relatively few and

minor in nature. Self assessment of the OOS program was aggressive and consistent

with the performance expectations of operations management.

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Operational Status of Facilities and Equipment

02.1 IdenhG;gligLQLLtakege in Unit 1 Drywell

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jnipaction Scop 3 (71707)

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The inspectors reviewed the issue screersing for Problem identification Form (PlF)

Q1997 04298. This PlF evaluated the continued operation of Unit 1 with leaking core

spray system Vent Valve 1 1402 66A.

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Qhignaugns and Findinos

During W &t* Wing cycle, Unit 1 drywell unidentified leakage increased from about

0.5 gah gp minute (gpm) in mid May to about 1.2 gpm by the end of September, Until

prompted by h inspectors, operations management was not aware of the adverse trend

in unidentified Unit i drywell leakage. On November g with leakage at about 1.5 gpm,

operators reduceo Unit 1 power, entered the drywell, and identified a core spray vent

valve spraying a plume of steam and water from the valve packing at about i gpm. The

valve (1 1402-66A) was closed, which would ordinarily prevent the packing from being

pressurized. However, the valse was leaking past the seat due to high pressure, high

temperature fluid cutting the valve seat, in time, neither the valve seat nor the valve

packing was able to contain the system pressure.

Engineers analyzed the condition as acceptable for continued operation of Unit 1. The

analysis determined the resultant plume of steam did not adversely affect environmental

qualification of equipment operating in the drywell In addition, the leakage rate was less

than the allowed unidentified leakage rate of 5 gpm as stated in TS 3.6.H. The leakage

was not considered to be pressure boundary leakage and in the event of an accident, the

core spray system would still be ab!e to deliver the design flow rate.

The inspectors reviewed the analysis and determined it was technically sound, but were

concemed that the condition of the valve would continue to degrade (due to steam

cutting) and cause the leak rate to increase. Additionally, the valve was not isolable from

the reactor vessel. The licensee planned to continue operation of the facility without

correcting the condition, but planned to repack the valve during an upcoming planned

outage (early January 1998). Operators implemented administrative limits for unidentified

drywellleakage which were more conservative than the TSs and monitored drywell

temperatures morr frequently.

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On November 25 the licensee identdled an additional soutoe of drywellleakage after

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uniastating the reactor core isolation coolmg (RCIC) system. The leak role (estimated to

be alot 0.5 gpm) was not identified during drywell walkdowns 2 weeks earlier.

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Until prompted W the inepectors, licensee management was not aware of the adverse

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trend in unidentifid leakage in the Unit i drywell. The inspectors concluded the

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licensee's evaluatiott of the unisolable leak was in compliance with T8s. However, the

licensee did not take proact!ve corrective action for the drywellleak once identified.

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Instead, licensee management chose to allow the unisolable drywell leak to continue for

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about three months until a scheduled maintenance outage.

07

Quality Aseuronse in Operations

07.1 ' Review of Licaname's Corrective Action Pronram

a.

Innoection Scone (40600,71707)

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The inspectors reviewed audits and monthly reports produced by quality and safety

assursace (QSA). The inspectors reviewed administrative procedures and spoke to

outside contractors brought in to audit the corrective action program (CAP). The

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inspectors reviewed corrective actions to various PlFs which consisted of root cause

evaluations (RCEs), licensee event reports (LERs) and apparent cause evaluations

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- (ACES). The inspectors attended plant onsite review committee (PORC) meetings, event

screening committee (ESC) meetings and selected root cause investigations. The

inspectors also reviewed the licensee's corrective action program performance indicators.

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Qhnetystions 4Ddfindinal

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Corrective Action Pronram Improvement initiatives

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in a letter from the NRC to Comed dated January 27,1997, the NRC was concemed with

the cyclical performance of Comed facilities.- The NRC expressed concem with major

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weaknesses in problem recognition and failure to ensure lasting corrective actions.

in a letter dated March 28, igg 7, Comed committed to implement a revised CAP at all

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the nuclear sites. The licensee implemented the following changes to the CAP at the

Quad Cities site:

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established a root cause export group and a staff of root cause investigators,

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modified the existing integrated reporting program, and

established common procedures and practices for implementing CAP across the

Comed system.

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Root Cause Evaluation Exoert Group

The RCJ expert group received special training in RCE methods, human error reduction,

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and error coding in an effort to improve quality of corrective actions, in addition, the

licensee provided training to a number of root cause investigators. The investigators

were assigned to lead root cause investigation teams. Each RCE produced by the root

cause investigators was reviewed by a RCE expert prior to the report being submitted to

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PORC for approval.

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IntegrainqLB_eportina Preggss Modifications

Corporate Comed standardized the integrated reporting system across all nuclear sites.

The licensee's new corrective action program system (CAPSYS) allowed for equal

comparison between sites of critical performance indicators. This allowed for a better

comparison of station performance. The CAPSYS also allowed for more detailed error-

coding of root causes. The improved error coding of the RCEs was intended to ensure

that proper corrective actions were assigned to prevent recurrence of problems.

Standardized Corrective Action Proaram lmolementina Procedures

An assessment by Comed corporate determined RCEs differed between sites and were

inadequate to prevent problems from recurring. Representatives from each Comed

nuclear site developed standardized Nuclear Station Work Procedures (NSWPs) to

improve the CAP. The licensee developed the NSWPs based on existing procedures and

methodologies used by Performance improvement Intemetional (Pil) and other nuclear

facilities. In May 1997, Quad Cities adopted NSWPs for Root Cause Evaluations,

Root Cause Investigations, Integrated Reporting Program, Effectiveness Reviews and

i

Apparent Cause Evaluations.

8tyltyvAQorrective Action Program by Independent Audliqr.j

Quad Cities employed Pil to perform a significant common cause analysis during the

summer of 1997. This analysis used LERs and RCEs as source documents to determine

the cause of significant problems at all Comed nuclear sites. The Pil auditors identified

that 60 percent of the significant problems at Comed nuclear sites were due to

noncompliance with administrative procedures. The licensee generated corrective

actions to address the noncompliance with administrative procedures. The corrective

actions were anticipated to be in place by the middle of 1998.

Additional audits of the implementation of the Quad Cities CAP performed by Pil

identified some process problems, program implementation problems and some

organizationalissues. The auditors identified various strengths including good

management support and good monitoring and trending which identified some

weaknesses with the licensee's surveillance program. The auditor concluded minor

course corrections were required, but that the implementation of the CAP was good,

considering it had been implemented within the last 7 months.

11

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.

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Corrective Action Proaram Performance Monstonna

j

in response to a 50.54(f) letter, the licensee committed to develop performance indicators

!

at each Comed nuclear site to measure the effects of changes made to improve the

CAP. Both Comed and Quad Cities published monthly reports which discussed CAP

performance indicators. The licensee monitored and reported four performance

indicators of the CAP to the NRC: Corrective Action items, Overdue Corrective Actions,

j

Repeat Events and Number of PlFs Written.

,

for the month of October 1997, the Quad Cities site judged the four CAP performance

i

indicators as a significant strength. However, Comed corporate office was less

,

impressed with the performance indicator results. Comed corporate office concluded the

'

CAP was generally improved with some exceptions. Comed corporate office

acknowledged the total number of repeat events for 1997 did not meet management

expectations. Comed corporate office judged the Quad Cities site CAP, relative to the

.

rest of the industry, as average in performance,

The Comed corporate office and the stations tracked other indicators not repor1ed to the

i

NRC as CAP performance indicators. In a November 1997 CAP monthly indicator report,

corporate judged Quad Cities CAP performance as below standards in some areas but

acknowledged continued improvement. Both the Comed corporate office and

Quad Cities management reports for November 1997 reflected weaknesses in

,

-

Quad Cities past due nuclear tracking system (NTS) items and the number of NTS items

'

extended.

in addition, the corporate office expected each nuclear station to perform at least 5 to 10

effectiveness reviews por month. Effectiveness reviews provided a systematic approach

to review the effectiveness of past corrective actions assigned to prevent recuxence of

previously identified deficiencies. Quad Cities had completed none in the month of

October.

Qug.lity23mpnce Audits

Based on performance, the QSA group audited the CAP twice a year. The audits noted

significant improvement in corrective actions to prevent recurrence. However, there were

still instances of ineffective corrective action. For example, the QSA group documented

on corrective action report CAR 04 96-045 that operators had not processed failed post

maintenance tests per procedural requirements. The station addressed the issue by

implementing corrective actions. The QSA group closed out the CAR in December 1996

based on corrective actions taken. However, a later audit identified the corrective actions

taken did not prevent recurrence of improperly processing post maintenance testing

failures. This condition was documented on PlF Q1997 02987. The QSA group

identified another 6xampit. of a CAR being closed based on corrective actions only to

identify the corrective actions did not prevent recurrence (PlF Q1997-02989). Similarly,

the QSA group opened CAR 04 97-017 due to a repeat finding of incomplete

documentation of contractor and vendor certifications required prior to contractors and

,endors working on site (see related issue in Section M1.3.). The QSA corrective action

program audits identified that root cause investigations were improving due to

implementation of the root cause experts and better review of packages by the plant

onsite review committee (PORC).

12

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The inspectors concluded the QSA group was identifying numerous issues. The station

was generally responsive to the issues identified. The departments' responses were

provided in a timely manner. The inspectors noted the QSA group identified some repeat

'

issues.

Mig _gf RCE invesligators

The CAP provided at least two root cause investigators for each functional area, with

extra RCE investigators for engineering. However, the number of qualified RCE

investigators had decreased due to attrition or demands for resources. For example, the

need for engineering resources resulted in some dedicated RCE investigators being

temporarily removed for other projects. During the period there were a large number of

engineering issues identiiled. The number of engineering issues and the reassignment of

RCE investigators resulted in 14 engineering RCEs needing extensions and 2 RCEs

being overdue.

Insoectors' Review of Selected Corrective Actions

Corporate assessments, QSA audits, and independent auditors concluded similarly that

the CAP was improving but still needed attention in order to be successful. The

inspectors reviewed selected RCEs, ACES and LERs and concluded the quality of the

documents had improved but also noted specific instances in this inspection report (See

Section M1.2) and previous reports where corrective actions did not prevent recurrence.

The quality of the implementation of corrective actions can be measured using

effectiveness reviews. However, as of the end of the inspection period, effectiveness

reviews had not been performed. The inspectors believed the effectiveness of the new

CAP to ensure that corrective actions were in place to prevent recurrence of previously

identified deficiencies, had not yet been demonstrated.

c.

Conclusions

The inspectors concluded the licensee implemented administratis a changes to the CAP.

The standardization of performance indicators was a good method for comparing and

contrasting site performance. The establishment of root cause experts and investigators

appeared to be a good initiative. But, the inspectors found that RCE investigators were

being pulled away from their assigned duties to perform other functions.

Comed corporate offices acknowledged the total number of repeat events for 1997 did

not meet management expectations. Similarly, the corporate office expected each

nuclear station to perform at least 5 to 10 effectiveness reviews per month. Quad Cities

had completed none in the month of October. Both the Comed corporate office and

Quad Cities management reports for November 1997 reflected weaknesses in

Quad Cities past due nuclear tracking system (NTS) items and the number of NTS items

extended.

The QSA group continued to identify CAP issues, some of which were previously

identified as weaknesses. Similarly, the inspectors noted specific issues of weak

corrective actions in this inspection report (See Section M1.2) and previous inspection

reports where corrective actions did not prevent recurrence. The inspectors concluded

13

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the effectiveness of the new CAP to ensure that corredive actions were in place to

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prevent recurrence of previously identitled deficiencies had not yet been demonstrated.

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IL Maintenance

. j

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M1-

Conduct of Maintenance

!

M1.1 General Comments

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a.

Inapection Scope (62707)

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The inspectors observed the effect of various maintenance activities and equipment

problems on plant operations.

'

b.

Observations and Findinas

i

!

The inspectors observed control room operations on December 3 and found that

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'

operators had placed Unit i foodwater control in single element control vice the normal

'

'

three element control at the request of maintenance. This action was taken at 5:07 a.m.

i

in preparation for instrument technicians replacing a main steam flow square root

4

instrument as directed by Work Request g700g0094. Single element control was not the

preferred method of control since the foodwater system cannot respond as well to teactor

i

- water level transients in this mode. At about 3:00 p.m. the inspectors questioned

operators and maintenance supervision, and found that the technicians had not yet

j

replaced the square root instrument, and probably would not de so until the next day, at

which time the feedwater control system would need to be in single element control. The

square root instrument to be installed had not been calibrated prior to the request being

.

given for operations to take feedwater control to single element, anJ delays in calibration

caused the work to extend past the planned completion time. Poor communication and

,

"

,'

planning between maintenance and operations contributed to the feedwater control

system being in an abnormal lineup for an extended period

'

'

' On November 1g a control room log entry indicated trouble with control rod movement for

Unit 1 Control Rod G4. In subsequent discussions with control room operators, the

'

inspectors found that this problem had been recurring frequently, and at least once, very

high differential pressure (several hundred pounds above the normal 300 paid range) was

>

+

required to move the rod. Due to the high differential pressuras used, operators were

l

required to go to the reactor building to monitor pressure wh6;iever the rod diff'culty

-

- occurred. . No PlF or operator work around was written to document this condition and

. there was no sense of urgency to correct the condition, which operators had to deal with

' on a weekly basis when exercising control rods,

!

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Funher review of records indicated three control rods with movement problems. System

engineers recorded problems with rod movement in some cases, but did not get the

deficiencies recorded on a corrective action vehicle such as an action request or PlF.

,

The system engineer suspected the problem with Rod G-6 was a timing problem, but had

'

not initiated action to correct the problem prior to December 23.' The inspectors observed

-

-

-

that the control rod did appear to move inward easily and had not shown degradation

during scram time testing, which indicated the rod did not appear to be stuck,

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Some maintenance activities were not well coordinated with the g::.o; sis departmord to

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minimise abnormal system imoups (feedwater control). One CidM system

problem (control rod drive) was not repaired or tracked in a corrective action system.

'

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M1.2 Corradire Adions for 4kV Breaker Failures

j

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.

a.

Inamedian Scope (62707)

The inspedors reviewed corrective actions for recent and past 4kV beaker failures.

b.

Qhantrationa_andfindiana

I

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On November 11,1997, an equipment operator observed that the Unit i emergency

i

diesel generator output breaker failed to recharge after the breaker was opened. - The

j

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breaker was a General Electric AMH Model 4160 voit horizontally racked circuit breaker.

Troubleshooting led to the conclusion that the most liksly cause for the failure was a

!

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loose wire on the power switch of the charging circuit. The inspectors found that the root

cause evaluation provided reasonable justification for this conclusion, but found that the

,

'

'

reason for the loose wire was not well understood and corrective actions were not

i

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necessarily comprehensive. For example, the licensee had not identmed in the root

!

cause toport that a preventive maintenance inspection for loose electrical connections

j.

recommended by the vendor for GE breakers was not performed at Quad Cities, The

l

"

inspectors found a number of other preventive maintenanos items not being performed at

Quad Cities, and found that the licensee had not provided sufncient reason not to perform

i

these tasks. Later, licensee engineers began the process to add a number of preventive

maintenance tasks to the breaker procedures.

,

I The inspectors also found that corrective actions for other Comed 4160 voit breaker

failures (including failures at Quad Cities) had not been implemented as planned, in

response to a 1996 event at the Comed Dresden station where a GE AMH breaker failed

i

to trip due to hardened grease, PIF 96 2154 was generated at Quad Cities. Engineering

response to the PlF indicated that Quad Cities had unrefurbished breakers that should be

!-'

replaced with overhauled breakers in order to address the aging grease issue. This was

'

especially applicable to Quad Cities because some of the breakers coatained lithium

'

grease which was susceptible to agi ig and found by analysis to have stiffened somewhat

~3

on Quad Cities broskers. An analysis was performed to justify allowing breaker operation

until June of 1997 at which time all unrtfurbished breakers should have been rep 6 aced.

>

Other plans included changing c..t a numtser of the GE breakers with Martin Gerin

-

-breakers in subsequent refueling catages. However, the inspectors found that in

November 1997 the unrefurbished GE breakers had not all been replaced, and no

justification for continued operation had been performed.

j

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On February 2,1997, closing springs on a safety related 4 kV GE AMH bisaker failed to

recharge due to suspected hardened lithium grease in the close latch beating, as -

documented in PlF 97-0373.1 Corrective action for the hardened grease condition was

= planaed for eight breakers the licensee cor.sidered critical for operation. The corrective

1

action included refreshing the bearings on these breakers with lubricating oil and

i

replacing them with refurbished breakers from Unit 2 following the Unit 2 Q2R14 refueling

,

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outage (which was scheduled to be complete in earty May 1997). However, on

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November 30,1997,5 months after the actual end of the Unit 2 refueling outage,5 of the

!

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8 breakers were not replaced wKh refurbished breakers and 4 of these breakers were not

i

lubricated with oil as planned. The breakers which had not been refurbished for 28 years

included the % Diesel Generator output breaker,1 A Core Spray pump breaker, the 18

Core Spray pump breaker, the 1D RHR pump breaker, and the Unit 1 Diesel Generator

j

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output breaker. This information was documented in response to corrective Action item

l

NTS 254 20197-037301.

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Engineering justification for continued breaker operability was based partially on the

-

inspections performed during preventive maintenance. However, the inspectors found

f

.

that the 3 year PM frequency for several of the GE breakers had been exceeded by as

!

!

much as 9 months, in other cases, the inspectors found that the vendor recommended

maintenance was not being performed on the required interval or not being performed at

all, eor example, the vendor recommended a 5 year overhaul frequency for the breakers.

But the inspectors found some cases of breakers that had not been overhauled in about

26 years. Quad Cities relied instead on a 3-year inspection PM to detect signs of breaker

,

d.

failure. However, the PMs failed to incorporate vendor recommendations for inspections.

'

Some of the checks recommended, but not incorporated, were visual checks of electrical

and mechanical connections of the breakers. The inspectors noted that the cause of the

1

November 11,1997, breaker charging failure was listed as a loose wire. This type of

failure could have been detected by inspections of electrical connections recommended

.'

by the vendor. Another breaker charging failure in July 1996 (PlF 96 2264) was also

'

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attributed to improper charging circuit wiring.

The inspectors found that other vendor recommended items were not being performed.

i

3

.

These itecluded a minimum of annual cycling of breakers to ensure grease and operating

,

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mechanisms remain intact, auxiliary switch height measurement, arcing contact velocity

check, minimuni voltage close test, arcing contact and arc runner clearance check, trip

latch clearance check, prop clearanca check, and high potential test when insulation

.

i

system components are repaired or replaced. Some vendor literature indicated that nct

performing some of these checks on a periodic basis was acceptable if the overhaul

i

frequencies were met, but Quad Cities did not met the 5-year overhaul frequencies as

noted above,

,

i

Failure to implement effective corrective action for breaker problems found at Quad Cities

in 1996 and 1997 was a Violation (50-254/97026 01; 50 245/97026 01) of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action."

,

uner problems found by the inspectors included the lack of maintenance rule goals for

the 4160 volt distribution system. From July 1996 to December 1997, a total of four

breaker charging mechanism failuren were found with GE AMH breakers at Quad Cities.

i

Two were due to faulty electrical wiring routing or connections, one was due to hardened

grease and one was due to loose springs. Although this system was considered in A1 of

the Maintenance Rule, no got or action plan for improving system performance wers in

place.

Add 6nally, the inspectors were told that' preventive maintenance procedures for some

Merlin Gerin breakers were not in place, although the breakers had been installed for

- abou' 2 years. The licensee was still relying on tie-wraps to hold the auxiliary contact

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switch assemblies in place on the Merlin Gerin breakers. The extent of the problem with

the Merlin Godn breakers was not yet determined at the end of the inspection period.

However, the inspectors did find that on another system, the station blackout diesels, the

PMs had not been implemented since the diesels had been placed in service about

2 years previously. This appeared to be a problem with ensuring that plant modifications

included all items necessary fx property functioning systems before being doolated

i

operable.

j

c.

Conclusion

[

Corrective actions for problems with important safety equipment were poor. The

.

inspectors found that corrective actions for 4kV breaker failures were not property

Implemented. Some breakers had been in service for about 28 years withou' forhaul

and contair,ed lithium grease which had been shown to be stiffening. Corrective action

deadlines to replace these breakers were not met. Corrective actions to maintain the

grease in a soft condition were not performed as planned. in addition, preventive

l

maintenance items to support property operating breakers were not being performed as

~

'

recommended by the vendor. Preventive maintenance items for new modifM:ations were

not in place after 2 years of system operation, indicating a process problem with

establishing PM requirements,

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M1.3 Valves Regag9mbled improperiv

l

a.

Inspection Scope (62707)

The inspectors reviewed problem information forms (PlFs Q1997-QO3974, Q1997 03789,

and Q1997 03721) and corrective actions for the improper reassembly of a valve. The

- inspectors also reviewed Work Package WR 950088052.

b.

Observations and Findinas

-

Upon disassembly of Valve 2 3213C (Unit 2 *C' Reactor Feed Pump minimum flow

valve), on October 8,1997, maintenance mechanics identifed the valves' pressure

retaining devices (segment rings) were missing. The licensee concluded the valve was

.

'

improperty reassembled during the previous refuel outage. Twelve pMssure seal ring-

type valves were worked by a contractor during the outage. The licensee identifed one

of these valves (Unit 2 high pressure coolant injection Steam Supply Valve 2 2301-4) was

i

!

assembled with the inner bonnet upside down. The reasons for both of these conditions

were attributed to human error (inattention to detail, lack cf questioning attitude, possible

knowledge deficiency and/or poor procedural guidance). Corrective actions included the

- proper repair of the valves, revision of valve maintenance procedures and st.bmittal of a

training request to raise awareness of this near miss event.

i

The licensee performed an apparent cause evaluation (ACE) for both of these problems.

The ACE was a low level corrective action program document that identifwd apparent

causes of the problem and corrective actions.- The inspectors reviewed the ACE

. corrective actions and identified the following issues were not identifed by either ACE:

'

The inspectors questioned the qualification of the individuals contracted to work

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the valves. The workers did not install the pressure retaining segment rings for

- 17

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the 2 3213C valve in accordance with the drawing and the 2 2301-4 valve inner

bonnet was assembled upside down.

Barriers (that is, quality control inspection, supervisory overview, etc.) typically

used to ensure quality work was performed in the station, were either not in piece,

or did not function properly,

The apparent cause evaluations did not provide sufficient information about the

+

cause of the even's to ensure proper corrective action coding.

The inspectors were concemed that skill of the craft errors were not detected by the

maintenance and/or testing program prior to operating the unit. In addition, corrective

actions generated by the ACES may not be effective to ensure similar problems would r.ot

recur. This is a Violation (50 265/9702642) of 10 CFR Part 50, Appendix B, Criterion V,

' Instructions, Procedures and Drawings.'

c.

qqngkalong

In these two instances, skill of the craft errors by contracted maintenance personnel were

not detected p-ior to operating the unit, in addition, proposed corrective actions did not

appear to be effective to ensure similar problems would not recur,

M1.4 Qgntinued Problems with Misand Technical Specification (TS) Surveillance Reauiremen13

a.

Mapection Scong (71707)

The inspectors followed up on the licensee's identification of several missed TS

surveillance requirements,

b.

Qhservations and Findinos

in Inspection Report 50 254/97014; 50 265/97014, the NRC issued a violation citing

numerous examples of the failure to perform required TS surveillances. These licensee-

j

identified issues along with previous examples of TS noncompliances prompted the

initiation of a root cause evaluation. Before the completion of the root cause evaluation,

the licensee identified two additional occurrences of missed surve;llances

(PIFs Q1997 03793 and Q1997-04121). The inspectors characterized these two issues

as an Unresolved item in inspection Report 50 254/9702102; 50-265/9702102 and

planned to review the corrective actions. A third exemple of a missed surveillance was

identified as a specific result of the corrective actions from the root cause evaluation.

All three of the missed surveillances referenced at'ove involved similar issues regarding

the failure to perform TS required channel checks or channel calibrations of required

instrumentation prior to changing modes as required specifically by Individual TSs and

also by TS 4.0.D. The failure to perform required surveillances was considered to be a

Violation (50 254/9702643; 50 265/97026-03) of TS 4.0.D.

These three missed surveillances had been reported to the NRC in licensee event reports

(50 254/97023,50 265/97023; 50-254/97025,50 265/97025; and 50-254/97026,

50 265/97026). The inspectors reviewed the planned corrective actions documented in

18

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the LERs and concluded that no additional response to this violation was necessary. The

inspectors planned to follow up on the adequacy of the corrective actions once

completed.

c.

Conclusions

The station identified examples of missed TS required surveillances. A root cause

evaluation was performed to address previous TS noncompliances. However, only one

of three of the new issues was identified as a result of corrective actionc from the root

cause evaluation.

M1.5 Observation of Maintenance Activities

a.

Insoection Scop.g (62707)

The inspectors observed two maintenance activities including the partial disassembly of

the 20 reactor protection system motor generator set and the 2B fuel pool cooling system

pump.

b.

Observations and Findinos

The inspectors observed a port!on of the disassembly of the 2B reactor protection system

motor generator set performed by electrical maintenance department personnel. The

workers attempted to raise the generator unit from its pedestal, encountered resistance,

but continued to raise the generator. The generator released from the pedestal with a

sudden jerking movement. The workers discovered that dowel pins were installed at an

angle in several of the feet of the generator unit. These pins had not been identified by

the procedure. The dowel pins were initially used to set the alignment of mechanically

coupled rotating equipment. Minor damage to the pedestal resulted, which was easily

repaired.

The inspectors observed mechanical maintenance department workers during

reinstallation of the 2B fuel pool cooling pump upper casing. As the casing was lowered

to the point of contact, the workers did not exercise adequate caution as the casing was

seated. This resulted in the casing seating with an abrupt motion as it contacted the

lower casing flange. The abrupt contact introduced the potential for intemal pump

component damage which could cause rework or limit the long term reliability of the

pump. However, there was no damage, and no rework was necessary,

c.

Conclusions

Two maintenance activities observed indicated a lack of appropriate caution nn the part

of the workers performing critical rigging tasks at the point where there was increased

potential for equipment damage.

M8

Miscellaneous Maintenance issues (92902)

M8.1 (CJQ19d13)nteEglygillent(t)RI) 50 254@ZQ2102: 50 265/97021-02: Missed Technical

Specification Required Surveillances. See Section M1.4. This item is closed.

19

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Ill Enginnadna

- E1 -

Conduet of Engineering

E1.1

General comments (37551)

During the inspection period, three In-Servios Test (IST) failures occurred. On UnN 1, two

valves, a primary containment isolation valve and a high pressure coolant iriection valve,

failed stroke time tests and were deriored inoperable. On UnN 2 both standby liquid

- control pumps failed the flow test (Section E2.1). In all three of the cases, irderim actions

to restore operability were taken, but corrective actions to address the cause of the test

failures were not implemented.

The licensee continued to focus on the resolution of previously identif6ed Appendix R safe

shutdown procedure problems. Althoug! Jnit 1 exNed the 67 day Administrative

' Technical Requirement (ATR) on December 2 (day 66), three subseqt,ent reentries into

the ATR were made within the following week due to continued identification of procedure

and equipmem defloiencies. The inspectors viewed the repeated ATR entries as an

, indication that the issues had not been adequately resolved prior to exiting the 67 day

ATR.

On December ig, NRC and licensee managers met in the Region lli offices to discuss

the Appendix R safe shutdown issues. Subsequent to that meeting, station management

socided to shut down Unit i due to the lack of a current safe shutdown ana!ysis to

suppost the operability review used to exN the 67-day ATR. Additional related issues are

discussed in Section E1.2.

E1.2 Current Appendix R. Safe Shutdown issues

a.

Inspection Scope (37551)

The inspectors continued to monitor the licensee's progress in resolving previously

identified issues with Appendix R safe shutdown procedures.

b.

Observations and Findings

Unit i exited the administrative technical requirement for inoperable safe shutdown paths

on December 2 which was day 66 of 67 of the ATR. The ATR would have required a

plant shutdown if the 67 day time period had been exceeded with the safe shutdown

paths inoperable. On December 2 new safe shutdown procedures (Quad Cities

Appendix R Fire Protection Procedures [QCARPs)) were approved for use and the safe

shutdown paths were declared operable, but degraded, via en operability review, which

concluded that while Appendix R compliance was not met, the safe shutdown f anctions

could be fulfilled.

The inspectors found the revised safe shutdown concept was an improvement over the

previous epproach. However, engineers identifw' d three procedure deficiencies within

one week after exiting the ATR and NRC inspectors developed several concoms that

remained untosolved (URI 50 254/g7021-02; 50-265/97021-02). Among these concems

were:

20

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The QCARPs were constevoted based on a nowh written, draft safe shutdown

.

anahsis that was incomplete and unroviewed.

The QCARPs did not receive the cross disciplinary review by the Appendix R .

,

+

coordinator prior to implementation,

j

!

~

No 10 CFR 50.5g review was completed for a complete transition from the

- j

previous method of achieving safe shutdown, which utilized the emergency diesel

generators.

'

generators, to the current method which requires the station blackout diesel

The licensee decided to shut down Unit 1 on December 1g due to the lack of a current

safe shutdown analysis. Unit 1 achieved cold shutdown on Dooember 20. Regional

{

inspectors and NRR staff continued to review technical issues related to the new safe

shutdown method in addition to the process issues discussed above.

. I

!

E1.3

Cor**lans on Corm of Enaineerina

q

The technical engineering approach to resolve the emerging Appendix R safe shutdown

)

issues was good. That is, the decisicn to simplify the method and reconstruct the design

!

and licensing basis was appropriate. However, the NRC continued to have conooms

"

'

regarding the process for changing the licensing basis, implementing new procedures,

and establishing the operability of the new safe shutdown method.

l

E2

Engineering Support of Foollities and Equipment

E2.1

Renetitive Standhv Uauld Control Pumo in-Bervice Test Failures

-

i

s.

Inantction Scop 1(g3702)

The inspectors reviewed the licensee's response and followup actions to the failure of

'

both Unit 2 standby liquid control (SBLC) pumps during the quarterly in servloe test (IST)

1

flow rate test. The licensee repoited the system failure to the NRC under 10 CFR 50.72

i

on November 20.

.

!

. b.

Observaligns and Findinos

During IST quadedy testing, with the reactor shut down and in MODE 4, both Unit 2

SBLC pumps were declared inoperable when the measured flow rate for each pump fell

'

into the required action range defined in the IST program, in this mode, the SBLC pumps

were not required to be operable. The licensee suspected flow indicator inaccuracies

rather than actual pump degradation since previous flow indicator problems had been

'

experienced on both units and both pumps were effected. An action request (AR) was

I

generated to calibrate and/or replace the flow indicator.

i

The' inspectors recalled at least three occasions in the past year n which one or more

,

!

SBLC pumps were declared inoperable for this same reason. A pavious 50.72 report for

L Unit 1 was made on April 7,1997. During that event, a plant shuttlown was initiated

since both pumps were inoperable, in all of these instances, the laterim solution was to

it: stall a newly calibrated (but same model) flow gauge and perfo'.m the surveillance

21

.

-

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.

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again. The inspectors also noted that the test was of little value in terms of the intended

purpose of trending since initial response to the test failures was to immediately suspect

the flow indicator.

The long term solution was to install a different type of flow meter. However, the design

engineering work had been delayed several times due to higher priority work. On

December 3 the Unit 2 test was satisfactorily completed with a replacement flow gauge

and the pumps were declared operable. The design change package to install a different

type of flow meter was scheduled to be completed mid December, but actualinsta'lation

had not yet been scheduled,

c.

QQaclusiOAt

The SBLC pumps periodically failed the IST due to low indicated flow. A long term

solution to replace the flowmeters had been delayed due to higher priority engineering

work. The inspectors were concemed that the current IST test was of little value since

when the pumps failed the test, engineers immediately suspected the flow meters.

IV. Plant Support

'

R1

Radiological Protection and Chemistry Controls

R1.1

Ifigtd;!L@ lion Area Boundarv incident

a.

langegligfdqqpg (IP 83750)

The inspectors reviewed the circumstances associated with a self revealing event where

an individual entered a high radiation area (HRA) without being signed onto the

appropriate radiation work permit (RWP). The inspection included a review of the

licensee's investigation, a review of applicable procedures and documentation, and

discussions with licensee personnel.

b.

Qhitty_ations_ and Findinal

On November 18 an engineer and two maintenance workers were proceeding to a reactor

core isolation cooling (RCIC) room to perform an engineering and maintenance walkdown

in preparation for maintenance work. As the individuals were proceeding to the RCIC

cubicle, they were querying each other as to which RWP they were using. This revealed

that two individuals were signed onto RWP 973007, while the third individual was signed

onto RWP 970008. The individuals retumed to the radiologically posted area entrance to

ask a radiation protection technician (RPT)if the individual on RWP 970008 had access

to the RCIC room. The RPT indicated that the RCIC room had been released from HRA

'

status and therefore, the walkdown could be performed while signed onto RWP 970008.

This RWP was for tests and plant walkdowns, but did not authorize access to HRAs.

Radiation Work Permit 973007 was for modification walkdowns in radiation areas and

high radiation areas.

22

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_

..

_ _ -

.

- _ _ -

.

'

.

.'

After consulting with the RPT, the individuals proceeded to the RCIC room via the Unit i

north RHR room, a posted HRA. While in the RHR room, the electronic dosimeter (ED)

wom by the individual signed onto RWP 970008 alarmed. Upon hearing the alarm, the

individualimmediately left the area and proceeded to Radiation Protection to report that

his ED had starmed.

Radiation Protection's investigation revealed that the individual entered the RHR room,

which was posted as an HRA with a swing gate at the entrance. Since the individual was

signed onto an RWP that did not authorize access to HRAs, the ED's dose rate alarm set

point was set at 10 millirem per hour (mrem /hr). The ED indicated that an area with a

dose rate of 24 mrem /hr had been entered, therefore causing the alarm. The ED also

indicated a radiation exposure of 0.7 mrem to the individual for this entry. In addition, the

investigation revealed that the individual had not entered an actual HRA (greater than

100 mrem /hr at 30 centimeters).

The licensee determined the root cause of this incident was the individual's failure to

completely understand the conditions and instructions on the RWP. Contributing to this

event was poor communication between the individual and the RPT, where the RPT

assumed the individual would go to the RCIC cubicle via a route that did not include entry

into an HRA. Once the individual was !nformed that he could go to the RCIC room, he did

not recognize that he could not enter an HRA while on his way to the cubicle.

Corrective actions included counseling the individual on requirements prior to obtaining

an ED. These requirements incit d reading and understanding the RWP and its

limitations prior to signing, and periodically reviewing the RWP to ensure understanding.

Radiation Protection personnel were briefed cn the incident and informed of the need for

broader communication when addressing worker questions. In addition, a greeter was

positioned at the entrance to the radiologically posted area to question individuals on

where they were going in the plant and if they were entering an HRA. Workers who

planned to enter an HRA were briefed on the high radiation aree access guidelines and

signed a high radiation access ticket. The ticket was used as a reminder of the access

guidelines and included the following information: 1) ensure high rad barriers and signs

remain in place; 2) ensure swing gate in place and closed behind you; 3) ensure high rad

area stanchions are not moved; and 4) ensure any discrepancies are communicated to

RP and maintain control of the area.

Quad Cities Administrative Procedure, QCAP 0600-06, Revision 6, " Radiation Work

Permit Program" states, in Section D.2.b.4, that individual workers signing onto an RWP

shall be responsible for complying with the requirements of the RWP and all associated

documents. Radiation Work Permit 97008 states in the specialinstruction section that

this RWP does not allow access to any high radiation areas. Therefore, entering a high

radiation area while on RWP 97008 was a violation of procedure QCAP 06006-06 and

RWP 970008. However, this non repetitive, licensee-identified and corrected violation is

considered a Non Cited Violation (50-254/97026 04; 50 265/97026-04) consistent with

Section Vll.B.1 of the NRC Enforcement Policy,

c.

CmcMIDDI

A violation of NRC requirements war identified for entering a posted HRA while signed

onto an RWP that did not authorize access to HRAs. This violation was a Non-Cited

23

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Violation due to licensee identillcation and effectivo corrective actions, which include

posting a grooter at the entrance to the r='-

-g'z"; protected area and ialliating the

high radiation access ticket program.

,

F1-

Conduet of Fire Protection

F1.1

Imolamentation of the Licensee's New Fire Protection Procedures

I

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!

a.

jnapaction Scope (71750)

The inspectors viewed the training and validation of the new Quad CMies Appendix R fire

.

protection procedures (QCARPs). The inspectors also observed compensatory action

training provided to operators which was needed to support the new Appendix R fire

l

protection procedures.

j

t

b.

Observations and Findinas

j

The licensee provided both classroom and laboratory training to a crew of operators on

the new QCARPs. Afterwards, the crew was given a fire scenano to validate the

!

- QCARPs,- The training provided was informative and resulted in good classroom

j

.

participation. The classroom handouts adequately discussed the basis of the new

1

'

QCARPs."The instruclor addressed pending modifications needed to support the new

- '

Appendix R program. During the laboratory portion of the training, the operators received

training on the local operation of electrical breakers.

,

During the scenario the inspectors identified certain walkways in both the turbine building

and station blackout building were not lit as required by Appendix R requirements.

Specifically, lighting packs provided in the station blackout diesel generator (SBODG)

building did not meet Appendix R requirements for 8-hour discharge times. Similarty,

'

operators were required to travel between the battery rooms (mezzanine level) and the

safety-related bus (turbine dock) during a fire scenario. However, there was no lighting

L on the steps between the Unit 2 turbine dock and mezzanine level.

,

in addition, the inspectors noted the licensed operator designated to operate the 8BODG

was not familiar with the local operation of the machine. The licenses had not trained

operators on the local opseation of the 880DG since the 8800G was operated from the

control room during previous scenarios. The unfamiliarity of the 880DG equiV erd and

}

building displayed by the operator, combined with other inefficiencies, resulted m the crew

l

not being able to meet certain time goals of the QCARPs. The licensee revised the

procedures and performed another procedure validation with a different operating crew.

<

Subsequently, the operators demonstrated the procedure could be executed in_the

j

- required time.

c.

Conclusions

The' inspectors concluded the 10 CFR Part 50, Appendix R, safe shutdown procedure

- training of the crew of operators was good.' The inspectors concluded the QC ARP was

!

not adequate to ensure specific actions wore completed within the time required. After

i

.

f revising the procedure, operaters demonstrated the ability to execute the QCARP in a

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s

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24-

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

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_ _ _ _ _ _ _ _ _ _

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timely manner. The inspectors ident46ed walkweys were not :t;:r; lit in accordance

'j

with Appendix R requirements (Section F1.1).

I

P1'

Conduet of Emergoney Preparednese

P1.1

Evaluatian of Linanmaa's Emergenc'( Pranarednans Drill

]

'

a.

Jnapaction acone (92904)

l

. .

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l

4

On November 5 the l6censee conducted a utility only, off hours emergency id:;Mwess

j

J

(EP) drill. The purpose of the detil was to evaluate the effectiveness of EP plans and staff

,

>

training to ensure a timely mobilization of utility personnel and resources. The inspectors

'

l

reviewed both operator and controller performance from the simulator control room during

,

portions of the drill.

!

1

9

b.

Observations and Findinns

j

1

'

The scenario started with Unit 1 in MODE 1 (power operations) when a loss of control

'

room annunciator circuNs occurred. Control room operators made Initial notifloations to

the state and local authorities within 15 minutes. Simulated cotivation of the emergency

response data system (ERDS) occurred about one half hour into the alert declaration. -

'

The NRC notifloations were initiated in about 45 minutes. Transfer of command and

j

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control of the situation from the simulator to the technical support conter (TSC) was

_

accomplished about an hour after the alert declaration. At that time, the TSC met

!

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minimum statnng requirements (the TSC communicator position was vacant).

i

' Overall, simulator control room operators effectively responded to the emergency

conditions. The operators' communications, including periodic briefings were informative

i

'

and timely. The controllers appropriately controlled the scenario in the control room.

l

'

.

!

'

During the scenario the shift manager declared an unusual event. However, drill

controllers prompted the shift manager to declare an alert. During the recent 1997

l

Dresden exercise, the corporete office of Comed determined the basis for emergency

action level (EAL) MA6 needed clartfloation on whether the loss of one of three control

room monitoring systems, or loss of all three systems were required, in addition to the

!

loss of annunoistors, to declare an alert. The corrective actions from this previously

!

'

identified EAL concem had not been implomonted prior to the use of this scenario for the

{

Quad Cities drill. However, discussion with the Corporate EP staff indicated that the -

t

'

basis for this alert EAL would be clarified during the next Generating Stations Emergency

l

Plan revision, scheduled for mid 1998. The inspectors considered the licensee's actions

,

_

to clartfy the EAL's basis as an inspection Followup item (80-254/97026 08,

!

80-245197026 08).

.

c.

Conclusions

6

L Ths inspectors concluded the exercise succes6fullu demonstrated the licensee's

-

capabilities to implements the EP plans and proceouros. Offsite notifications and -

i

activation of the TSC were within time limits, CWsol room r / armance was good. An

inspector followup item was idereified concoming the we 9A6s $s in corporate Comed

corrective action to clartfy the basis for alert EAL. MA6.

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- 25

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_ _ _ _

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P8

Miscellaneous Emergency Preparedness issues

8.1

LClosed) Inspection Followuo item (IFI) (50-254/96011 10: 50-265/96011-10): Exercise

Control Problems. During a previous NRC evaluated emergency preparedness exercise,

the inspectors noted weaknesses in controller performance in the simulator control room

as well as unanticipated equipment operation during the scenario. The inspectors

observed the most recent EP exercise and determined controller puformance had

improved and there were no unanticipated simulator control room problems. This item is

closed.

V. Manaaement Meetinos

X1

Exit Meeting Summary

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

conclusion of the inspection on December 23,1997. The licensee acknowledged the findings

presented. No proprietary information was identified.

X2

Pre Decisional Enforcement Conference Summary

On November 26,1997, a predecisional enforcement conference was held at the NRC Region til

office to discuss potential enforcement issues identified in inspection Report 50 254/97017;

50-265/97017. The issues related to Quad Cities Maintenance Rule (10 CFR 50.65)

implementation.

X3

Management Meeting Summary

A management meeting to discuss 10 CFR Part 50, Appendix R, safe shutdown issues was held

at the NRC, Region lli Office, on December 19,1997.

26

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._

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f

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PARTIAL UST OF PERSONS CONTACTED

Ucannes

E. S. Kraft

Site Vice Presidens

L W. Pearce

Station General Manager

D. B. Cook

Station Manager

R. V. Fairbank

Acting Engineering Manager

B. L. Sharer

Assistant Maintenance Manager

R. G. Svaleson

Operations Manager

88G

A. B. Beach

Regional Administrator

G. E. Grant

Director, Division of Reactor Projects

f

M. A; Ring

Branch Chief

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27

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n.

INSPECTION PROCEDURES USED

IP 37551:

Offsite En9 neering

.

i

IP 40500:

Effectiveness of Ucensee Controls in identifying, Resolving, and Preventing

Problems

l

1

IP 62707:

Maintenance Observations

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

IP 83750:

Occupational Exposure

i

IP 92902:

Followup - Engineering

IP 92904:

Followup - Plant Support

IP 93702:

Prompt OnsHe Response to Events at Operating Power Reactors

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-254/97026-01; 50 265/97026-01 VIO

corrective actions for 4 kV breaker failures

-

50-265/97026-02

VIO

valves reassembled improperly

50-254/97026 03; 50 265/97026-03 VIO

missed TS surveillances

50 254/97026-04; 50-265/97026 04 NCV high radiation area boundary incident

50 254/97026-05; 50-265/97027 05 IFl

evaluation of licensee's emergency preparedness

drill

Gl91td

'

50 254/9702102; 50-265/97021-02 URI

missed TS required surveillances

50 254/97026-03; 50 265/97026-03 NCV high radiation area boundary incident

.

50 254/96011 10; 50 265/96011 10 IFl

exercise control problems

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LIST OF ACRONYMS AND INITIAL /SMS USED

ACE

Apphrent Cause Evaluations

APRM

Average Power Range Monitor

AR

Action Request

ATR

Administrative Technical Requirement

CAP

Corrective Action Program

'

CAPSYS

Corrective Action Program System

CFR

Code of Federal Regulations

Corned

Commonwealth Edison Company

EAL

Emergency Action Level

ED

Electronic Dosimeter

EDG

Emergency Diesel Generator

EO

Equipment Operators

EOOS

Electronic Out of Service

EP

Emergency Preparedness

ERDS

Emergency Response Data System

ESC

Event Screening Committee

EWCS

Electronic Work Control System

GE

General Electric

gpm

gallons pcr minute

HPCI

High Pressure Coolant injection System

HRA

High Radiation Area

IASM

Interim Altemate Shutdown Method

IDNS

tilinois Department of Nuclear Safety

IFl

inspector Followup item

IPEEE

Individual Plant Examination Extemal Events

IST

in service Test

kV

Kilovolt

LCO

Limiting Condition for Operation

LER

Licensee Event Report

N/A

Not Applicable

l

NSO.

Nuclear Station Operator

NSWW

Nuclear Station work Procedures

NTS

Nuclear Tracking System

005

Out of Service

POR

Public Document Room

PlF

Problem identification Form

Pil

Performance Improvement Intemational

PM

Preventive Maintenance

PORC

Plant Onsite Review Committee

QCAP

Quad Cities Administrative Procedure

QCARP

Quad Cities Appendix R Fire Protection Procedure

QCMM

Ot.13 Cities Mechanical Maintenance

QOS

Quad Cities Operating Surveillance

QSA

Quality and Safety Assurance

RCE

Root Cause Evaluations

RCIC

Reactor Core Isolation Cooling System

RG

Regulatory Guide

RPS

Reactor Protection System

i

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J'

RPT

Radiation Protection Technician

RWP

Radiation Work Permit

SSLC

Standby Liquid Control

SBODG

Station Blackout DieselGenerator

880

Safe Shutdown

TS

Technical Specmcation

TSC

Technical Support Center

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved item

Vdc

Volt direct current

VIO

Violation

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30