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Insp Repts 50-254/88-07 & 50-265/88-08 on 880328-0407.No Violations Noted.Major Areas Inspected:Hpci/Rcic History & Mgt Activities,Root Cause Determination & Corrective Action & Maint Activities Re HPCI & RCIC
	ML20151Z621
Person / Time
Site:	Quad Cities
Issue date:	04/28/1988
From:	Hasse R, Lanksbury R, Phillips M, Vandel T; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20151Z616	List: ML20151Z611; ML20151Z621;
References
	TASK-1.C.6, TASK-TM 50-254-88-07, 50-254-88-7, 50-265-88-08, 50-265-88-8, NUDOCS 8805050326
	Download: ML20151Z621 (22)
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U.S. NUCLEAR REGULATORY COMMISSION

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REGION III

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Report No:

50-254/88007; 50-265/88008

Docket No: 50-254; 50-265

License No:

DPR-29; DPR-30

Licensee: Connonwealth Edison Company

Post Office Box 767

Chicago, IL 60690

Facil'. y Name: Quad Cities Nuclear Power Station, Units 1 and 2

Inspection At:

Cordova, Illinois

Inspection Conducted: March 28 through April 7, 1988

Inspectors:

R. D. Lanksbury

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Team Leader

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R. A. Hasse

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T. E. Vandel

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NRC Contractor:

D. A. Beckman

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Approved By:

M. P. Phillips, Chief

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Operational Programs Section

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Inspection Summary

Inspection on March 28 through April 17, 1988 (Report No. 50-254/88007;

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50-265/88008).

Areas Inspected:

Special announced inspection on HPCI and RCIC operating

problems. Areas inspected included HPCI/RCIC history and management

activities, root cause detennination and corrective action, maintenance

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activities related to HPCI and RCIC, system walkdowns, and HPCI and RCIC

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surveillances.

Res ults : Of the five areas inspected no violations were identified. However,

two open items were identified to track licensee conmitted corrective actions

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of inspector concerns.

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8805050321, 880429

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ADOCK 03000254

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DETAILS

1.

Persons Contacted

Commonwealth Edison Company (CECO)

N. Kalivianakis, General Manger, BWRs

R. L. Bax, Station Manager

T. K. Tamlyn, Production Superintendent

R. A. Robey, Services Superintendent

I. M. Johnson, Nuclear Licensing Administrator

D, A. Gibson, Regulatory Assurance Supervisor

N. P. Smith, BWR Licensing Supervisor

J. Kopacz, Technical Staff Supervisor

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M. Turczynski, Site BWR Engineering Supervisor

D. Rajcevich, Master Instrument Mechanic

D. W. Craddick, Master Electrician

J. Fish, Marter Mechanic

C. H. Norten, Quality Assurance Engineer

G. Price, Maintenance Department

K. Hill, Technical Staff Engineer

J. Wethington, Quality Assurance Superintendent

The inspector also contacted and interviewed other licensee and contractor

personnel.

Nuclear Regulatory Commission (NRC)

D. M. Crutchfield, Director, Region III, IV and V Projects, NRR

N

J. Chrissotimos, Deputy Director, DRS, RIII

R. F. Dudler Technical Assistant, NRR

B. Siegal,

. censing Project Manager, NRR

R. M. Learch, Branch 1 Technical Assistant, DRP, RIII

R. L. Higgins, Senior Resident Inspector, RIII

R. D. Lanksbury, Reactor Inspector, RIII

R. A. Hasse, Reactor Inspector, RIII

"T. E. Vandel, Reactor Inspector, RIII

D. A. Beckman, Parameters, Inc.

Denotes those attending the exit meeting on April 7,1988.

2.

HPCI/RCIC Functional Inspection

This inspection was prompted by the relatively large number of High

Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling

(RCIC) system outages over the past several years. The purpose of the

inspection was to determine if these systems were capable of reliably

performing their design functions, were being operated and maintained in a

manner supportive of reliable operation, and to determine if adequate

corrective actions were being taken in response to identified problems.

The inspection was conducted by a review of system design, modifications,

surveillance activities, maintenance, corrective actions taken in

response to identified problems, and actions taken on the recomendations

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generated by the licensee's HPCI/RCIC Task Force. This Task Force was

established by the licensee in 1986 to evaluate the problems with these

systems and recommend actions to improve their reliability.

3.

HPCI/RCIC History and Management Activities

This area of inspection was perfomed by the inspection team to evaluate

the licensee's analysis of the data gathered through various review

prosesses, actions taken to resolve concerns generated as the result of

the various reviews performed, and the status of implementation of generated

recommendations,

a.

Task Force

The HPCI/RCIC Task Force was composed of a multi-discipline team of

plant staff personnel, a member of the corporate BWR Engineering

Staff, and a General Electric representative. The responsible

technical staff systems engineer was the team leader.

The Task Force first met on July 17, 1986, to consider RCIC

reliability with the defined tasks of:

Focus on improvement of turbine performance and reliability.

Establish four modification packages to:

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1.

Add motor operators (M0's) to turbine trip and throttle

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valves for both the HPCI and RCIC systems.

2.

Remove low lube oil pressure RCIC turbine trip.

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Increase pipe size of RCIC turbine bearing drains.

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Remove unused sections of RCIC turbine lube oil piping.

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Develop a modification to remove RCIC turbine electrical

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overspeed trip.

Develop an outage surveillance on the turbine lube oil system,

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Develop an auto-initiation surveillance on both HPCI/RCIC.

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Subsequently, the task force added the following reports into

their areas of concern for resolution.

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a.

INP0 station evaluation report, March 1987,

b.

Quality Assurance Audit Report 04-86-56, May 19, 1987,

and,

c.

Final Report of Safety System Inspections, January 15,

1988.

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May

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June

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July

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August

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September

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October

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November

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December

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Totals

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Certain valves contributed substantially to these DVRs. These are

tabulated separately as follows:

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HPCI Valve 2301-48 (4" M0 valve, for make-up from

condensate hot well or recycle)

9 DVRs

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HPCI High Temperature Isolation Switch

5 DVRs

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RCIC Valve 1201-48

4 DVRs

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RCIC Electrical Operating Switch

6 DVRs

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The predominant work crafts involved were mechanical and electrical,

primarily related to valve, controller and operator repair and

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replacement.

Examples of the types of problems being experienced

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common to both the HPCI and RCIC systems were as follows:

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Stem packing leaks and bent stems

M0 valves failing to travel full stroke

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Open shunt windings

Flow controller failures (replacement)

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Steam exhaust check valve seat failures

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1201/2301 - 48 valve motor mount failures (vibration)

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The preventive maintenance (PM) listing in b.(1), above, were defined

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by the licensee, as items for which work was performed before a failure

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occurred. However, they were actually routine scheduled repair work.

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The team believes that these routine maintenance items, along with the

types of valve problems listed above, could be easily corrected by a

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well developed PM program. A PM program that utilizies trending tech-

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niques, end of life histories, and other indicators coordinated with

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scheduled system repair / replacement can assure system dependability.

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This programmatic concern is further expanded later in this report.

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c.

Audits and Other Management Information

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Auditing activity, related to the HPCI/RCIC systems, were reviewed.

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The items covered were as follows*

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Audit Report #04-86-56 Safety System Modification Review Unit 2

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HPCI system, May 19, 1987.

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This was a comprehensive audit of the HPCI system covering

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activities and documents, in-process work requests, surveillances,

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and completed post modification testing.

Nine findings and five

observations were generated related to Technical Specifications,

design, documentation, and testing deficiencies.

The separate functions covered by this audit included the

following:

1.

25 trodification design packages were reviewed (100% of

Uni'. 2 HPCI modifications) by auditors qualified to

independently perform the design analysis and verification.

2.

Field walk downs of accessible piping systems.

3.

In Service Inspection (ISI) documentation review.

4.

Environmental Qualification (EQ) review of all items

required to be EQ.

5.

Maintenance activities review of over 100 completed WR's.

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Operation requirements and Technical Specification matrix

requirements activities review to verify compliance.

The licensee's assessment was that the HPCI and RCIC systems were

continually capable of perfonning their committed design function even

under abnormal conditions.

The team reviewed three of the nine findings for followup and close out.

Finding #2, although current, continues open for the next refuel outage

and for the next FSAR update to complete. The resolution and changes

were being adequately resolved.

Findings #8 and #9 have been acceptably

completed and closed.

The team considered this to be a comprehensive audit performed by

qualified people and documented adequately.

However, programmatic

concerns were not covered during this audit, such as the concerns

addressed later in this report.

One additional audit (No. 4-87-19) and four surveillance reports

(4-87-07, -33. -52 and -58) regarding follow up and closed out

activity for DVR's were completed with satisfactory results.

The team inquired as to the types of information being reported to

appropriate management regarding significant deficiencies (as required

by Appendix B Criterion XVI). Following is the information provided

to the team:

1.

A QA 60-day report is routinely provided to corporate management

regarding unresolved audit report findings in excess of 60 days.

2.

A goals presentation for the Quad Cities Station was held on

November 12, 1987, in which the significant deficiencies of the

HPCI/RCIC systems were presented to top corporate management.

3.

Action Item Requests (AIR's) are developed by the plant

technical staff and issued to the BWR Engineering Division for

their control of problem items most likely to develop into

modifications. On site technical staff indicated that 5 AIR's

have been issued related to HPCI/RCIC.

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The plant technical staff also develops trending information in

accordance with plant administrative procedure QAP 400-14,

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Revision 2, with a monthly trending report being issued primarily

to plant management.

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No violations or deviations were identified.

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4.

Root Cause Deter:nination and Corre?tive Action

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The team reviewed the adequacy of the licensee's root cause determination

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and corrective actions related to problems with the HPCI and RCIC systems.

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The team was especially concerned with the root cause determination for

those failure types with no ' prior history along with their associated

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corrective actions and the corrective actions for failures termed as

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end-of-life failures.

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An example of the first type involved the arcing of push button contacts at

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the local control station for the HPCI suppression pool suction valve

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(DVR-2-87-013).

The arcing was caused by moisture and dirt which had

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accumulated in the switch contacts resulting in a continuous "open" signal

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(valve is normally closed). Apparently, since there was no prior history

of this failure, corrective action involved cleaning the contacts and

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returning to service. An example of the end-of-life failure. involved the

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packing failure on a unit one HPCI steam supply valve (LER 86-034).

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this case the root cause was determined to be failure due to normal weer

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and the corrective action involved packing replacement and return to

service.

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The team's concern in these cases was the failure of the licensee to

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address the issue of preventing recurrence that is inherent in the concept

of corrective action.

In the case of the dirty contacts, the failure to

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determine tne root cause (e.g., environmental conditions) precluded

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correcting the basic problem.

The alternative for preventing recurrence.

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periodic cleaning of the contacts (planned maintenance), was also not

addressed.

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In the case of the packing failure, the end-of-life failure might be

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considered a root cause. However, it is probably more accurate to state

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the root cause as failure to anticipate the end-of-life failure and to

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take action to replace the packing prior to in-service failure.

In either

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case the corrective action is the same, planned maintenance (or preventive

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maintenance in the absence of service life information).

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The licensee indicated that both the NRC and INP0 had previously expressed

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concerns in the area of the licensee's root cause determinations. As a

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result. the licensee was in the process of preparing a program to address

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this issue (error free program).

This program will require that the

person (s) evaluating the more significant events have completed the

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Management Oversight and Risk Free (MORT) training.

Events of lesser

significance would be analyzed by person (s) having completed the in-house

training on root cause analysis (already implemented).

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The team reviewed the lesson plan for the in-house training on root cause

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analysis.

The training was based on the MORT concept of barrier analysis

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and the Kepner-Tregoe change analysis process. While the materials

covered were pertinent and well prepared, the inspectors did have several

concerns.

First, the amount of material covered appeared to be too much

for the one day allotted for the training.

Secondly, it appeared that

additional empnasis could be placed on tha concepts of root cause deter-

mination and corrective action as it applies to mechanical failures (e.g.,

the dirty contact problem discussed above) vs. software failures (e.g.,

management controls).

Licensee management should consider these concerns in the development of

their corrective action program.

No violations or deviations were identified.

5.

Maintenance

A general review of the corrective and preventive maintenance programs as

they applied to the HPCI and RCIC systems was conducted.

This included a

review of the administrative procedures in place for maintenance control,

of detailed work procedures, of prior system maintenance records, and of

personnel training and qualifications. Additionally, the status of the

preventive maintenance program and its implementation, including equipment

performance and trending information, was also reviewed.

a.

The team reviewed the following maintenance administrative procedures,

using them as a basis for review of maintenance activities on the

subject systems and their auxiliaries.

QAP 500-3

Maintenance Procedures

Revision 5

QAP 500-4

Inspection of Test and Maintenance

Activities

Revision 3

QAP 500-6

Maintenance Records

Revision 1

QAP 500-9

Preventive Maintenance

Revision 2

QAP 500-15

Conduct of Maintenance

Revision 2

QAP 700-1

Training

Revision 2

Training and qualification records were reviewed for electricians

(ems) and instrument mechanics (IHs). The team found that in the last

several years the number of relatively new personnel had increased and

had reduced the previously high average experience level of the de-

partments.

This was due to staff transfers to newer CECO plants and

staffing increases at Quad Cities.

The number of fully qualified

"A"

(journeyman) level personnel is approximately equal to the number of

"B" level personnel in training in each department.

According to the

Master Electrician, EM staffing has been increased from twenty to

thirty three ems; similar increases are underway in IM staffing.

The licensee has implemented an INP0 accredited craf t and technician

training program for both initial and continuing training for these

posi ti ons .

The team found that, although many of the incumbents had

been exempted from the INPO initial training, a regular program of

continuing training was in progress with the annual training comit-

rent recently increased from 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> per year per person to 80

hours.

The "B" level personnel are participating in initial training

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at the Braidwood Production Training Center and the site training

center, Job specific "B" level training is also provided by a

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structured "on the job" training program. The team reviewed the

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licensee's methods for control of personnel assignments versus-

training level and found it to be effective.

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b.

Corrective Maintenance

Corrective maintenance was not conducted on the systems during the

inspection. Work Request packages for rea nt prior repairs were

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reviewed along with the specific work proceddres applied:

Work Request

Description

Q55637

Repair of U2 HPCI HE Pipe Whip Restraint

Q54711

Valve 2-M0-2301-6 Dual Indication & Control Problems

Q59496

Troubleshoot U1 HPCI Emergency 011 Puep Breaker

Q61499

Valve 1-M0-1300-16 Failed to Auto Close

Q62696

U1 HPCI Gland Seal Blower Failure

Q55039

U2 RCIC Turbine Outboard Bearing Reduced Oil Flow

Q12130

Reposition U1 RCIC Turbine Thermo Well

Q56255

U2 HPCI Turbine Speed Control - No Response

Q56376

Adjust U2 HPCI Speed Control Circuits

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Q5603

U1 HPCI Turbine Will Not Reset from Control Room

Q57381

Replace Stem & Repack Valve 1-2301-4

058731

Remove U-Bolt Support 2-1301-H11

058734

Remove Rod Hanger 1-2301-H5

058735

Remove Hod Hanger 1-2325-H66

Q62908

Unit 1 RCIC Gland Seal Condenser Pump Runs Backwards

The packages were generally found to include complete records of

repair. All work involving modification of existing systems was

authorized by an approved modification package. Although the "Tests

Required" section of the Work Request forms was frequently brief and

incomplete, the packages contained records of post maintenance testing

adequate to reestablish the functionality and operability of the

affected equipment.

The packages contained, where appropriate, mate-

rial issue and certification documentation, inspection records, and

completed procedure copies. Measurement and test equipment usage and

calibration status was documented and acceptable. The work instruc-

tions were reviewed to determine that they conformed to administrative

requirements, included sufficient detail to address the problem, and

sufficiently complemented the "skills of the craft". Use of vendor

technical information was found to be controlled in accordance with

the Vendor Technical Infomation Program (VTIP). Machinery history

data was updated, but its use was limited.

The team noted that failure causes were typically oversimplified and

could cause inaccurate application of trending data.

For example,

Work Request Q62696 (above) was listed as a normal wear failure al-

though the corrective action involved cleaning and adjustment of

auxiliary contacts, i.e. an apparent need for a routine upkeep

activity.

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Review of the licensee's specific corrective maintenance in response

to the HPCI and RCIC betterment programs found the licer.see's o.tions

to be generally effective.

The licensee is continuing to experience

some difficulties with system auxiliaries and accessories. Examples

of this include an attempt to reset the Unit 2 RCIC cooling water

pressure regulator and it failed to respond to adjustments. Also,

during a surveillance on the same system, the team observed several

steam leaks and a governor lube oil leak requiring repair. Although

the licensee's betterment plans appeared comprehensive and proactive

as discussed elsewhere in this report, the systems appear to require

continued attention,

c.

Technical Specifications

A review of facility technical specifications was performed in order

to determine what, if any, impact they had on system reliability /

performance. The team determined that the licensee's technical

specifications were more restrictive than technical specifications

of most newer plants and the requirements contained in NUREG-0123,

Revision 3, Standard Technical Specifications for General Electric

Boiling Water Reactors (BWR/5).

The major distinction between the technical specifications is that the

facility technical soecifications require an immediate demonstration

of operability for tae backup system, whereas the NUREG-0123

requirement only requires that the backup systen be operable (i.e.,

the licensee has a current surveillance showing that the systems are

operable).

In addition, the facility technical specifications also

require daily testing which is not required by NUREG-0123.

The RICI

system technical specifications has similiar distinctions.

The team believes restrictiveness of the facility technical

specifications are basically a disincentive for the license to

perform routine corrective maintenance on the HPCI and RCIC system.

Rather than impose all the additional testing on the backup systems,

the licensee perfers to accept small steam, water, and oil leaks, and

other small problems that do not effect system operability, versus

declaring the system inoperable in order to effect repairs. This not

only leads to the systems being in a less than desirable condition

but these small deficiencies may propogate and ultimately become the

precurser to a system failure. The team recommended that the licensee

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pursue a technical specificatian change to bring the HPCI and RCIC

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technical specifications up to the current standards for non-operability

action.

In addition, the licensee should review their technical

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specifications for other similiar problems.

The licensee indicated

that they would pursue this course of action.

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Preventive Maintenance

The licensee's current preventive maintenance (PM) program is described

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by QAP 500-9 (above) which includes a general preventive maintenance

and surveillance pr ogram, a maintendnce history file system (the CEC 0

wide Total Job Management (TJM) System), a vibrational analysis program,

a lubrication program, and provisions for trend analysis.

The team

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found that although each of the above elements was in place to some

degree, the overall PM program was weak. The team was unable to

observe any preventive maintenance on the HPCI and RCIC systems since

none was perfomed during the inspection. The programmatic elements

and records of PM were reviewed with the following results:

(1) The program for predictive maintenance included vibration analysis,

motor operated valve testing and associated trend analysis but

did not include a program for data collatior, and trend analysis

of other maintenance related trends.

Periodic maintenance such

as scheduled lubrication, cleaning, adjustments and inspection

was found to be in-place for certain equipment such as switchgear

and instrumentation.

Planned maintenance, such as regular valve

repacking, overhauls, replacement of items with known life spans,

etc., appeared to be limited to "when needed" scheduling instead

of regular periodic performance.

Essentially no periodic or planned maintenance was provided for

the HPCI and RCIC mechanical components.

For example, only one

mechanical preventive maintenance procedure existed for the RCIC

system, QMPM 1300-1, RCIC Refuel Preventive Maintenance,

Revision 1, issued February, 1988, which provides for oil change

and lubrication.

None was provided for HPCI, Although the

licensee indicated that the pumps and turbines are opened,

inspected and overhauled periodically, ainimal preventive

maintenance of system auxiliaries was provided. As discussed

elsewhere herein, the licensee's approach to the HPCI and RCIC

bettenient activities also concentrated on corrective actions

and had minimal consideration of programmatic and preventive

actions for recurrent upkeep of the systems.

(2) Although QAP 500-9, Section C.5, required trend analysis of

general PM and surveillance results, Inservice Testing (IST)

results, vibration monitoring results, Work Request data, cali-

bration data, and Deviation Reports (DVRs) and Licensee Event

Reports (LERs), no consolidated program of trend analysis was

actually implemented as a method to determine the need for PM.

Although interviewed personnel generally had a good knowledge of

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equipment problem history and current status, the scope of PM

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activities appeared to be driven by either specific regulatory

initiatives (e.g. environmental qualification programs) or chronic

problems challenging plant availability.

For example, the

licensee is implementing QAP 2100-1, Conduct of Reliability

Related Activities, Revision 1, for non-safety related equipment

to improve generation reliability but had no similar program for

safety related equipment and systems, such as HPCI and RCIC.

The licensee also has a "Maintenance Rework Reporting Program"

implemented by Maintenance Department Memorandum No. 46.

This

progran only identifies repetitive repairs for individual compo-

nents, (e.g. rework of the Unit 1 HPCI turbine governor would be

identified but identical failures requiring individual repairs on

both Units 1 and 2 governors would not necessarily be identified).

The rework program, therefore, does not fulfill the intent of

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QAP 500-9, nor meet the needs for input to PM planning and scoping.

Trend analysis was formally applied to IST and vibration monitoring

data.

Some causal factor trending was applied to LERs and DVRs.

Informal review of calibration data trends was also observed as

part of instrument maintenance and surveillance activities.

However, essentially no broad based trending of Work. Request or

other failure data was conducted for safety related systems.

Quad Cities participates in the Nuclear Plant Reliability Data

System (NPRDS), but staff interviews found that it was rarely

used and the licensee had difficulty in retrieving review data

requested by the team.

Similarly, the licensee maintains a

computerized preventtve maintenance and surveillance scheduling

system (GSRV). The inaintenance department staff had difficulty

in retrieving GSRV preventive maintenance status information for

April 1988, and the report eventually provided by the licensee

included essentially no safety related equipment information and

contained numerous "last performed /next due" data errors.

The corporate wide TJM system appears to include extensive work

and failure history information.

The system has been in place

about two years and, although some historical information is

still being entered, the system does not appear to be used for

detailed analysis of equipment performance.

For txample, the

team noted a regular history of failures for air operated valves

and their accessories (solenoids,

I/Pconverters,etc.). The

licensee was generally aware of the failure history but had not

evaluated the possible trend because the failures had not chal-

lenged plant availability rior impacted Technical Specification

operability. The team noted that, although QAP 500-9 stipulated

that the functions above be accomplished, specific responsibili-

ties for the review and analysis of the data were not specifically

assigned and no one appeared to be held accountable for the

function.

As part of the CECO corporate INP0 goals, the licensee has recently

approved Directive N00-MA.2 and "Conduct of Maintenance at Nuclear

Power Stations" for company wide application.

This 120 page

document redefines maintenance activities and responsibilities,

defines standardized plant staffing elements, and provides a

broad new program for preventive maintenance and maintenance

history use, and appears to address the team concerns and licensee

program shortcomings discussed above.

Team interviews indicated

that this program is expected to take about three years to fully

implement.

Additional licensee management attention appears warranted to

fully use the information available for development and imple-

mentation of preventive maintenance activities sensitive to

equipment performance.

No violations or deviations were identified.

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6.

System Walkdowns

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a.

HPCI and RCIC Rooms - General Condition

Prior NGC inspection of these rooms had found that the general

structures and equipment appearance and state of preservation

were poor. The HPCI rooms and equipment had recently been re-

painted and preparations for painting the RCIC/ Core Spray rooms

were in progress.

During a tour of the HPCI and RCIC/Cere Spray rooms on March 29,

1988, the team observed that the Unit 2 RCIC room was being

prepared for painting.

The team found that the painting crew had

begun to install plastic sheet (drop cloth) masking and scaffold-

ing over RCIC and Core Spray pumps and equipment (scaffolding is

further discussed below). Both systems were considered to be

operable with respect to technical specifications. The floor was

strewn with loose bundles of plastic sheeting and untaped sheeting

was draped over the piping, valves and pumps.

Sheeting over the

Core Spray pump had the potential for blocking cooling air exhaust

from the pump motor and was loosely draped in the vicinity of the

pump shaft and thus providing the potential for entanglement in the

shaf t and blocking of motor air inlets. Additional sheeting was

installed over the RCIC pump and turbine, including the trip and

throttle valves, and had partially melted cn the steam supply piping.

The System Engineer accompanying the team insnediately removed sheeting

which appeared to represent the greatest risk of fouling system

components if system initiation occurred.

The licensee also dispatched

an Operating Engineer to inspect the room.

The Operating Engineer's initial inspection of the room concluded

that the conditions did not directly affect system operability

Subsequent inspection by the Production Superintendent, however,

.ndetermined that the conditions were unacceptable and resulted in

rearrangement of the plastic sheeting, removal of excess material,

u

and provision of additional instructions to the contractor painting

crews.

The licensee further confirmed, in response to an inspectors

question, that the plastic sheeting was fire retardant and did not

present a combustible hazard.

The Production Superintendent advised

the team that the Operating Engineer had been coordinating the painting

activities with the contractor crews but that the team had observed

the conditions prior to the Operating Engineer's planned final

inspection of the painting preparations.

b.

Temporary Scaffolding Installations

As part of the painting and general pre-outage preparations, contractor

crews had insti.lled scaffolding in the HPCI and RCIC rooms (and

elsewhere). L'e team found scaffolding erected above valves and

instruments and tied off to safety related equipment (air piping,

conduit,etc.).

The team expressed concern regarding the prudence

of, and procedures available for, control of non-seismic scaffolding,

susceptibility of the scaffold to installation errors and mechanical

failure, post installation inspection, and safety of transient loads

13

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

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_

.

,

over and/or scaffolding secured to systems and equipment considered

,

operable with respect to TS.

The licensee reinspected the installations and modified and retied

the scaffolding to more appropriate structural members.

They advised

the team that interim guidance hac been previously provided to the

installation contractor and that a draft administrative procedure

had been developed for long term controls. This procedure was expected

to be issued during April, 1988.

The team reviewed QAP 1700-7,

Scaffold Control Requirements (DRAFT), and found that it addressed

general considerations for such installations, including "Seismic

Class !! over I" considerations but did not include several other key

fac tors .

It did not provide for a safety evaluation, addressing the

criteria of 10 CFR 50.59, of sceffold installations with respect to

review of hazards to operable safety related equipment, availability

of unaffected redundant systems, control of transient overhead loads

on the scaffold, etc.

These aspects were discussed with the Assistant

Superintendent Maintenance who said that appropriate revisions would

be made to the draft procedure prior to issuance and guidance would

be used in the interim.

This is considered an open item pending NRC

review of the final program (254/88007-01; 265/88008-01).

c.

Calibration Status - RCIC Room Reactor Vessel Level Local Indicators

local reactor water level indicating differential pressure instruments

1/2-1360-28 and 1/2-1360-29 are installed in each RCIC room. The team

noted that the calibration stickers on level indicators bore calibra-

tion dates from 1977 through 1984.

Review of Instrument Department

records determined that the actual latest calibration dates were 1984

for both Unit 1 instruments and 1983 and 1987, respectively, for the

Unit 2 instruments. The instruments are used for reactor level control

if operating the RCIC system locally in accordance with Q0P 1300-9,

RCIC Local Manual Operation Procedure,

Revision 6, which is used as

part of Abnormal Procedure Q0A 010-5, Plant Operation with the Control

Room Inaccessible, Revision 5.

The team further determined that these

instruments are not currently included in plant procedures or schedules

for periodic recalibration.

The Master Instrument Mechanic advised

the team that the instruments would be included in the periodic recal-

ibration schedule.

The frequency of calibration was under evaluation

at the end of the inspection but was expected to be on the order of

once per five years with recalibration of at least the Unit 2

instrument scheduled for the outage beginning on April 10-11, 1988.

No violations or deviations were identified.

7.

Surveillances

The team reviewed surveillance activities applicable to the HPCI and RCIC

systems including review of operations and maintenance surveillance proce-

dures and data and observation of a monthly perforTnance test of the Unit 2

RCIC system.

14

a.

>

.

-

.

a.

Program and Procedures

The surveillance procedures, scheduling and performance data were

compared to Technical Specifications (TS) 3 2/4.2, Protective Instru-

mentation, and 3.5/4.5, Core and Containment Cooling Systems. Current

Operations Surveillance Test Assignment Sheets QOS 005-S2, -S3, -54,

and -SS were also reviewed for conformance with TS.

In addition, a

sample of operations and maintenance procedures were reviewed using

the guidance of NUREG/CR-1368, Development of a Checklist for Evaluat-

ing Maintenance, Test, and Calibration Procedures Used in Nuclear

Power Plants, Appendix C, "Procedures Evaluation Checklist". Proce-

dures reviewed are listed below. Those annotated with a single aster-

'

isk (*) included review of performance data.

Those indicated with a

plus sign (+) included review per the NUREG/CR-1368 checklist.

Each

procedure was also reviewed using its referenced piping and instrumen-

tation diagrams and electrical schematic diagrams to verify the

technical accuracy of the test methods.

Revision

QIS 7-1*

Drywell Pressure Calibration

2

QIS 7-2*

Orywell Pressure Functional Tests

3

QIS 11-1*

Low Low Reactor Water Level Calibration

4

QIS 11-2*

Low Low Reactor Water Level Functional Test 4

QIS 15-1*+

HPCI Reactor Low Pressure Analog Trip

4

System Calibration

QIS 15-3*+

HPCI Reactor Low Pressure Transmitter

4

Calibration

QIS 16-1*+

PPCI Steam Line High Flow Analog Trip

5

System Calibration

QIS 17-1*+

RCIC Reactor Low Pressure Calibration

3

QIS 17-2*

RCIC Reactor low Pressure Functional

4

Test

QIS 18-1*

RCIC Steam Line High Flow Calibration

3

QIS 18-2*+

RCIC Steam Line High Flow Functional Test

5

QIS 27-1*+

HPCI Turbine Area High Temperature Isolation 7

Calibration

QIS 28-1*t

RCIC Turbine Area Hi Temperature Calibration 10

QMS 700-4+

HPCI Logic Functional Test

13

QMS 700-3+

RCIC Logic Functional Test

14

QOS 1300-1*+

RCIC Monthly Test (observed performance)

6

QOS 1300-3*

RCIC M0V Operability Test

3

QOS 1300-7*

RCIC Manual Initiation Test

1

00S 2300-1*

HPCI Pump Flow Rate Testing Operations

13

Q05 2300-2*

HPCI Pump Operability Test (Monthly)

10

Q05 2300-3*

HPCI Valve Operability

4

QOS 2300-4*

HPCI Power Operated Valve And Check

7

Valve Testing at Cold Shutdown

Q0S P300-6*

HPCI Power Operated Valve Test - Every

4

.

90 Days

Q0S 2300-13*

HPCI Hot Fast Initiation Test

1

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.

b.

Procedure Review Findings

The Quad Cities units were licensed in 1971-72 and most operating,

surveillance, and maintenance procedures have evolved from those origi-

nally in place at the time of licensing.

The licensee has recognized

that the plant procedures require upgrading to meet current NRC and

INP0 standards and had begun a progressive procedures improvement

program.

Mechanical and electrical maintenance and surveillance

procedures were being rewritten with substantial progress made at the

time of this inspection.

Plans for the next two to three years in-

cluded continuation of this effort.

The "new" procedures reviewed were found to be a substantial improvement

over the unrevised procedures and appeared to include both the technical

detail and human factors elements considered necessary to enhance

pc monel performance and permit strict procedure adherence.

The

unrevi ed procedures were generally found to contain minimal technical

instruction detail and relied heavily on craft knowledge and skills to

effect successful completion.

In the past, the licensee had maintained a very stable craft work

force having extensive plant specific experience.

As a result of

personnel transfers to other new CECO facilities and Quad Cities staff

growth, the experience level of the in house staff has declined, with

about half to two thirds of the Electrical and Instrument Maintenance

Departments craft personnel being in an initial training status and

having two to three years (or less) station experience. The relative-

,

ly low average experience levels, combined with the existing proce-

dures' requiring a heavy reliance on skills of the craft, emphasized

the need to expedite the procedures upgrade program.

One example of

difficulties resulting from procedure inadequacies experienced during

an instrument calibration activity is further discussed below.

Review of completed maintenance and surveillance data found that the

licensee's programs were generally effective in identifying and

correcting unacceptable results.

The licensee has, in some cases,

progressively adjusted acceptance criteria and techniques to accommo-

date observed variations in calibration and equipment performance trends.

For example, the nominal calibration of RCIC Steam Line High Flow

instruments has been adjusted to provide a comfortable margin between

the maximum observed instrument drift, the technical specification

limiting condition for operation setpoint, and the normal operating

range.

The team found no cases in which anomalous data or unsatis-

factory results were not identified and processed by the licensee's

corrective action and reporting programs.

The procedure observations b0 low each typically apply to a number of

similar procedures even though only limited examples are provided.

l

QAP 1100-3, Station Procedure Periodic Review, Revision 15, includes

checklists for review of procedures which contain some of the elements

discussed below:

NUREG/CR 1368 contains others. The procedure

upgrade and review program should be reviewed by the licensee to

ensure that it is effective in identifying and addressing these and

similar procedure weaknesses. Specific observations include:

16

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. _ , _

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.

i

(1) QIS 15-1, HPCI Low Reactor Pressure Analog Trip System Calibration,

provides calibration of channel trip units and associated

circuits quarterly but provides for transmitter calibration only

once per operating cycle. Technical Specification Table 4.2-1,

HPCI Isolation, Low Reactor Pressure, Amendment No. 90 requires

channel calibration to be accomplished once every three months.

The existing table footnotes provide no exception for the

transmitters.

Discussions with Regulatory Assurance personne' determined that

Note 10 had been inadvertently deleted from technical specification

Table 4.2-1 during a prior amendment and had previously permitted

the transmitter calibration only once per cycle.

A proposed

technical specification Amenduent had been prepared restoring the

note, had been approved by the Onsite Review function in late 1987

(OSR No. 87-39), and had been submitted to Offsite Review (Item

No. 88-02) on February 18, 1988, for routine processing. This

finding is similar to that involvir;g incorrect technical specifi-

cation presentation of area temperature monitoring channels.

(2) The licensee's program for independent verification of prepar

return to service of safety related equipment appears weak.

NUREG 0737, Clarification of TMI Action Plan Requirements. Item

I.C.6, Guidance on Procedures for Verifying Correct Performance

of Operating Activities, requires that, for the return to service

of equipment important to safety, a second qualified operator

should verify proper system alignment unless functional testing

is used to verify that all equipment, valves, and switches are

correctly aligned. The licensee had committed to conformance

with Item I.C.6 and has included independent verification provi-

sions in the procedures reviewed.

However, the methods used for verification and documentation

provide the potential for personnel oversight.

Typically, both

'

the return to service lineup instructions and the independent

verification instructions each consist of a single, generalized

line item which covers numerous individual valve, switch, jumrar

wire, lifted lead, or relay block verification steps. Examp'es

include:

QOS 2300-1, HPCI Pump Flow Rate Test, involves extensive

-

valve and switch manipulation.

The procedure steps art not

individually signed off.

Rather, Data Sheet QOS 2300-31 is

used to document completion and single line action items

"Verify HPCI system readiness per Q0P 2300-1" and "Indepen-

dent Verification of Operability Status Following Test",

each requiring a single signature provide the only guidance

for verification the multiple return to normal steps.

Q0S 2300-3, HPCI Valve Operability Test, cycles about 15

-

valves with return to service posit'ons verified only by a

single entry check off list.

17

.

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.

. ..

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_-

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

-

.

,

Calibration procedures such as QIS 7-1, Drywell Pressure

-

Calibration, typically use only a single line verification

signature for independent verification of valve return to

service alignment.

In other procedures, such as QIS 28-1, RCIC Turbine Area

-

High Temperature Calibration, jumper wires are extensively

used and removal verification is provided by return of the

jumper wires to the control room.

In each case above, the methods used do not provide step by step

control of the verification process and, in some cases, require

the verifier to scan an entire procedure to determine which

components were disturbed and their respective final conditions.

In one case. QOS 2300-3, it was not clear that independent

verification was either required or performed although interviews

indicated that it had been. The above represent only selected

examples of such practices. Nearly all procedures reviewed

included some ambiguity or single step verification directions.

The team believes that the methods described above provide a high

potential for return to service realignment and independent

verification errors. The manner in which the realignments and

verifications were documented did not permit a detemination

whether the required individual equipment actions were actually

perfonned as required.

(3) Many procedures not yet revised under the upgrade program

provided precautions, limitations and actions only in the front

section of the procedure rather than preceding the action step

i

to which they applied, providing the potential for oversight.

4

For example, QOS 2300-1. HPCI Pump Flow Rate Testing, includes

eight precautions and seventeen limitations and actions which

'

warrant consideration for incorporation into the procedure action

step sequence.

(4) As indicated above, procedures typically do not require step by

step signoff. Data and required action signoffs are included in

l

separate data sheets and tables which become the documentation of

l

performance. The "linkage" between procedure action steps and

the data sheets is typically poor with data sheet step numbering

,

either absent or different from the equivalent procedure steps,

'

particularly for operating surveillances, instrument functional

tests and calibrations.

For example, the data sheets for Q05

,

2300-1 and 2300-3 include no step numbering or cross references

<

to the procedure. The data sheet numbering mismatches with the

procedure step numbering for QIS 28-1 and QIS 28-2.

The QOS

2300-2 data sheet for as left conditions includes no instructions

{

for completion or reference to the procedure action steps. As a

result the data entries were completed differently for six test

performances (both units) between December, 1987 and February,

,

1988.

18

,

?;

'

.

f

'

(5)

In nearly every case reviewed, acceptance criteria tolerances

were not expressed as ranges but rather as +/- values requiring

,

the performer to mentally calculate acceptability of results.

For example, QIS 27-1 provided an acceptance criteria for'the

1

,

HPCI area temperature isolation function of 185, +5, -10 degrees

'

i

F. rather than a range of 175 - 190 degrees F.

This practice is

contrary to fundamental human factors principals.

(6) Detailed work instructions were frequently found to be overly

!

general and relying heavily on the skills and knowledge of the

craft.

Further, .in several cases,

the instructions were suffi-

+

ciently general to permit variations or errors in performance

which could affect test outcome, particularly for less experi-

i

enced personnel.

For example, QIS 28-1 requires repetitive

,

i

installation of jumpers to test isolation logics but the instruc-

tions are provided by a single, generalized Step F.2.

Similarly,

i

QIS 17-1 includes instructions for testing the RCIC Reactor Low

'

!

Pressure Isolation when actual reactor pressure is above the

i

!

channel setpoint, requiring manipulation of switches but provid-

i

ing only generalized instructions rather than a step by step

i

method.

(7) The team observed performance of QIP 1600-3, Suppression Chamber

l,

Water Level Indication Calibration, Revision 1 on April 5,1988.

The team reviewed the above procedure and the work package for

Work Request Q65444 issued for the work and observed the first

I

half shift of initial attempts to calibrate. The "A" journeyman

Instrument Mechanic assigned to the task had previously performed

,

the calibration and appeared familiar with both the equipment

!

installation and procedure. Pre-job preparations appeared com-

1

plete with the necessary tools, material, and assisting personnel

available.

The instrument transmitter was located in the RHR P.com,

>

immediately beneath the RHR Heat Exchanger head in a 100 - 700

,

!

mrem radiation field. Additional semi-permanent test equipment

!

(calibration manometer, regulated air supply, valving, etc.) was

!

located opposite the transmitter wall mount in the torus area.

Initial difficulties were encountered in alignment of the trans-

.

I

mitter isolation valves, test manometer and air supply. The

!

equipment is located about 15 feet above floor level in the torus

area and is partially obstructed by piping.

The procedure provided

1

'

general valve lineup instructions for the test equipment which did

j

not match the actual installation. Due to the physical arrangement,

j

the technician could not see the entire test rig and had to manipu-

late the system by "feel" from a small elevated grating.

As a

result of the procedure not including valving actually installed

in the test equipment, the initial attempt to pressurize the

l

equipment for test was unsuccessful due te closed valves.

l

Procedure Step 7 instructs the performer to check the instrument

calibration and recalibrate if required.

Procedure Step 7, Note,

-

!

states "For calibration methods, see Barton Instruction Manual

l

(iiodel 368)". The connection points for the milliammeter could

i

!

19

{

. _ - - _ _ _

.

. .

'

.

not be identified in the procedure or instruction manual by the

technician. The technician initially connected the meter in a

manner he believed to be correct. This connection was incorrect

and the circuit's power supply fuse blew.

Subsequent discussion

with the Master Instrument Mechanic determined that the meter

connection points were specified in the "Limitations and Actions

Section" of the procedure instead of the "Procedure" section and

had been overlooked by the technician. Additionally, the speci-

fied points involved connection of the meter at the indicator

unit in the control room rather than at the calibration work

location.

Connection at the specified control room location

would have further compounded the difficulty of performance

requiring the technician to make local adjustments at the trans-

mitter while being directed via telephone by the person remotely

reading calibration meter. This represents an example of multiple

procedure deficiencies impacting the effectiveness of the

procedure.

Following fuse replacement, initial attempts to recalibrate the

transmitter were unsuccessful due to apparent instability in the

circuit electronics.

Additional difficulties were encountered

in maintaining a stable test air pressure due to poor response

from the semi-permanent test air regulators.

The procedure and equipment difficulties also detracted from

ALARA performance. Although the technician prudently minimized

his exposure in the higher radiation fields at the transmitter,

an extension of the normal 100 mrem daily exposure limit was

required after one half shift of work with the transmitter still

uncalibrated. The technicians exposure rate was approximately

2-4 times that of the inspector (who witnessed most of the work

from a designated ALARA waiting area within the room, about 8 - 10

feet from the transmitter).

ALARA considerations were discussed

with the Production Superintendent, Assistant Superintendent

Maintenance, and a Radiation Protection Supervisor on April 5.

The team concluded that, except for the procedure and equipment

deficiencies, the ALARA practices applied to the job were

acceptable.

The procedure deficiencies were discussed with the license

management, who indicated that the subject procedure was

generally known to require improvement but was not considered

technically inadequate. Team interview results with IM Depart-

ment personnel had indicated that this procedure was considered

difficult to perfom and that there were other similar examples

of poor instrument procedures. The licensee advised the team

that QIP 1600-3 would be revised to improve its perfonnance

prior to its next use but that the Instrument Procedures were

not scheduled for near term rewriting under the procedure upgrade

program in that they were believed to be in better overall

.

condition than the electrical and mechanical procedures which

were receiving higher priority.

20

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l

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In response to the specific team observations for this procedure

(

and the general procedure observations previously discussed, the

-

licensee committed to take the following actions to ensure that

1

any similar problematic procedures would receive priority

attention:

Instrument Department personnel would be polled to identify

-

ML20151Z621

Text

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