ML20154G864

Insp Rept 50-482/88-200 on 880606-17.Potential Enforcement Findings & Observations Noted.Major Areas Inspected:Line Organization Support & Contribution to Plant Quality & Quality Verification Organization Abilities Re Deficiencies

ML20154G864
Person / Time
Site:	Wolf Creek
Issue date:	09/16/1988
From:	Correia R, Finkel A, Hawkins F, Hopkins P, Hunter D, Moore R, Paul Prescott, Scott Sparks, Weiss S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV), Office of Nuclear Reactor Regulation
To:
Shared Package
ML20154G849	List: ML20154G845 ML20154G864
References
50-482-88-200, NUDOCS 8809210095
Download: ML20154G864 (26)

See also: IR 05000482/1988200

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Enclosure 3

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U. S. NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

Report No. 50-482/88-200 Docket No. 50-482 License No. NPF-42

Licensee: Wolf Creek Nuclear Operating Corporation

Post Office Box 411

Burlington, Kansas 66839

Facility. Wolf Creek Generating Station .

Inspection At: Wolf Creek, Burlington, Xansas, June 6-17, 1988

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Inspectors- *

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Richard P. Correia, Senior Operations Engineer

T!h!fd

(Date) i

NRR(TeamLeader)

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Perry C. Hopkins, Res'ident Inspector

9b6k]

/ (Dite)

Region !!

S(RMik

Randolph L. Moore, Reactor Inspector

vHn

/ (Date)

Region II

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Scott E. Sparks, Reactor Inspector / (Date) c

Region II

SYUN k

Dorwin R. Hunter, Senior Reactor Inspector

4/n

[(Dite)

Region IV

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Allen E'. Finkel, Reactdr Inspector / (Date7

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Peter J. Prescott, Qudlity Operations ' Engineer / (Date)

NRR

Reviewed by: I (

CDTikins, Chief, Qu111ty Operations Section /(Dite)

i NRR ,

Approved by: . 7/(!80

5. H. Weiss, Chter, Quality Assurance Branch /(Da%J

NRR

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SUMMARY

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Areas Inspected

This special, announced Nuclear Regulatory Comission (NRC) team inspection was

the seventh in a series of NRC Headqttarters-directed Quality Yerification

Function Inspections (QVFIs). The inspection was performed to assess the line

organization's support and contribution to plent quality and the quality

verification organization's ability to identify, solve, and prevent the occur-

renct 4 safety-significant deficiencies in the functional areas of plant

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a, is and maintenance. Another area that was evaluated during the QVFI

he effectiveness of management in ensuring that identified quality

j- t .. fencies were responded to promptly and completely.

l Results

Within the functional areas of operations and maintenance, six potential

enforcement findings (pEFs) were identified: (1) six examnles of not taking

appropriate corrective actions to prevent recurrence of plant system and

l component deficiencies, (2) not having procedures and instructions appropriate

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for the bearing removal activities on a component cooling water pump,

(3) not obtaining and performing evaluations of applicable service information

letters from the emergancy diesel generator vendor, (4) not verifying that four

seismic and vibration control supports were installed on the emergency diesel

generator turbocharger cooling water piping as specified by the vendor's design

drawing, (5) not posting a fire watch after a fire barrier seal.in a penetration

was determined to be unqualifier', and (6) not declaring a loop of the Essential

Service Water System inoperable when it '.4s determined it did not meet its :

specified design requirements. 7

In addition, two observations were identified: (1) a lack of a feedback

mechanism for maintenance personnel to report problems and recomendations to ,

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procedure write n , and (2) a lack of an adequate methodology to calibrate the

resistance temperature detectors for the reactor coolant system.

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1 INTRODUCTION

This special, announced NRC team inspection at Wolf Creek Generating Station

(WCGS) sas performed to evaluate the acceptability of the line and quality

verification organizations' activities and management's support of these

activities. The inspection was the seventh in a series of NRC headquarters-

directed inspections performed.under the guidance of NRC Inspection Manual

Temporary Instruction 2515/78, "Inspection of Quality Verification Functions."

The inspection consists of personnel interviews, direct observation of in-

process activities, and review of work documents.

Quality Verification Function Inspections (QVFIs) are not intended to verify

licensee compliance to administrative controls; they are intended to verify the

technical adequacy of safety-related activities. However, if deficiencies are

tvund in these activities, the underlying procedures and adminictrati';e con-

trols are reviewed. The intent of these inspections is to improve plant opera-

tional safety through inspection processes that are focused on activities that

affect plant safety and reliability.

The QVFI at Wolf Creek focused on plant operations and maintenance of plant

systems ud components. The inspectors reviewed selective samples in these and

closely associated areas to identify safety-significant problems to be used as

the vehicles for evaluating the effectiveness of quality achievement and

verification. The results of this review are discussed below and the

inspectors' more significant findings are categorized as potential enforcement

tind!ngs and observations.

Potential enforcement findings are apparent violations of regulatory require-

ments that will be further evaluated by NRC Region IV management for possible

enforcement action. Observations are items that may not violate any regulatory

requirements and may not violate plant procedures, but that appear to be less

than optimum. Observations are being referred to NRC Region IV and NRC

Headquarters Staff and may require inspectors to perform followup reviews

during subsequent inspections.

2 PLANT OPERATIONS

2.1 Control Roon and Operations Activities

2.1.1 Inspection Results

The NRC inspectors observed control room and other eractions activities,

interviewed control room personnel, and reviewed rertinent documents related to

operations activities. The inspectors observed control room decorum, control

rocm shif t turnover during dayshift and backshift, main turbine valve cycling,

mainte,ance and testing of the reactor trip breakers, a valkdown of the auxili-

ary feedwster system, and a transient involving a loss of automatic feedwater

control and the subsequent recovery in the control room. The team inspected

other plant areas to verify operability of equipment, control of igniti.

sources and combustible materials, proper condition of fire detection L.

extinguishing equipment, adequacy of maintenance activities, and adequat.

of selected surveillances.

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Control room shift turnovers were orderly and briefings of individual operators

were adequate. The NRC inspectors observed that the oncoming shift conducted

another briefing for all operators after the off-going shift had left the -

control room. During these briefings (generally less than 5 minutes in dura-

tion), the operators discussed scheduled surveillance testing and general plant

status information. During the QVFI, the plant experienced a loss of automatic

feedwater control that led to a system transiant. The operators quickly

assessed the plant condition and responded to avoid a reactor trip on a low

steam generator water level. The NRC inspectors observed that during the shift

turnover briefing

attentive after the

to the briefing transient, incoming

information. shift operators

The licensee's were very(QA)

Quality Assurance

organization has audited this area several times and has not identified any

problems with the adequacy and effectiveness of shift turnovers.

The NRC inspectors noted on several occasions that the operations manager and

plant manager were in the control room observing shift turnover activities,

other plant evolutions, and the shift supervisor's activities durinq differ-

ent evolutions. At most times, an additional senior reactor operator (SRO) was

available during the day chift. There also was good administrative-clerical

support for the supervisors and operating staff. These support personnel

appeared to remove some of the administrative burdens from the control room

staff.

Management appeared to support quality operations and responded well to

operators' recommendations concerning the use of operator aids in the control

room. For example, a suggested operator aid, which consisted of a magnetized

plastic card inscribed with the technical specification requirement and limit-

ing condition of operation (LCO), was used on the engineered safety features

actuation system bypass panel. This magnetized cara covered the bypass key

lock. When a system channel had to be bypassed, the operator aid had to be

removed before inserting the key. The card then was placed in front of the

control room operator to serve as a constant reminder of the condition that had

to be monitored.

Managecent also has provided opportunity for operators to part'cipate in a

.ollege training program. These personnel are . ant to a local university to

gain college credit towards meeting qualification requirements for a shift .

' technical advisor (STA) position. There were times when several SR0s on the

l same shift had the qualifications of an STA, which provided extra crs of

i technical expertise to evaluate specific plant problems. The NRC .mpectors

l observed that this program appeared to create higher morale and lower person-

nel turnover.

lne NRC inspectors observed plant operator surveillance activities of technical

l specification requirements for safety-related systems and components. The

inspectors also observed the licensee's GA overview of these operator surveil-

lance activities. The QA personnel who were observed provided effective identi-

fication of problem areas during their overview. The NRC inspectors observed

portions of 22 selected surveillance tests aru all aspects of several other

tests. Qualified personnel performed the tests and properly calibrated required

test instrumentation, and the resulting data met the requirements of the Tech-

nical Specifications. When discrepancies were identified, they were rectified

and the systems were properly returned to service. QA personnel were present

while NRC inspectors observed surveillance tests.

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The NRC inspectors watched tag out and equipment restoration on several

occasions.. The tag out and restoration processes, including briefings, were

well understood bv all operators who were involved. The NRC inspectors .

observed that QA personnel regularly reported and followed up on fintiings

in these areas.

The NRC inspectors also watched operators pwform a cycling test of the main

turbine valves in accordance with Procedure STS AC-001, Revision 5. This

surveillance-test demonstrates the operability of the turbine overspeed pro-

tection system as required by Technical Specifications. The operators compe-

tently perforaed the test, and they adhered closely to the procedure. The test

was satisfactorily completed without any irregularities or component mal-

functions.

The NRC inspectors performed an auxiliary feedwater (AFW) system walkdown with a

reactor operator using Procedure CKL AL-120, Revision 10, "Auxiliary Feedwater

Normal Lineup," and piping and instrumentation diagram (P&ID) drawir.g M12AL01(Q),

Revision 0. The NRC inspectors determined that the actual system configuration

agreed with the P&ID drawing and that the operator appeared knnwledgeable

of valve locations and proper valve positions. The valves were found to be

free of corrosion, locked if required, and positioned in agreement with the

P&ID and the procedure. During the walkdown, the NRC 1:. pectors identified

fotrvalves(EF-V07/,FC-V115,AB-V085,GF-V009)withnolabelsandonevalve

(AL-V035) that contained a small packing leak. The reactor operator noted all

deficiencies and they were corrected after being discussed with plant management.

During the AFW

turbine-driven AFWwalkdown,(the

pump TDAFWP) NRC

speedinspectors

set point on noted that theshutdown

the auxiliary position of the

panel did not agree with required TDAFWP set point noted in Procedure CXL

AL-120. The required speed set point was 3850 rpm, while the actual control

set point was 5750 rpm. The inspectors discussed this discrepancy with cogni-

zant instrumentation and control (I&C) personnel, who explained that the TDAFWP

shutduwn parel controller output signal to the pump is 3850 rpm, regardless of

the higher set point. 1&C personnel also provided, as a verification of this

condition, the results of the testing of the TDAFWP controller conducted on

j October 23, 1987, in accordarce with Prucedure INC L-1000, Revision 2. The

NRC inspectors discussed the TDAFWP speed set point with several operations

personnel and determined that operator knowledge of equipment operation was

i Meeptable.

2.1.2 Results Sumary

The NkC inspectors observed during multiple dayshifts and backshifts that

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control room operators conducted themselves in a professional manner.

Operators appeared to be attentive, were knowledgeable of plant status, and

performed testing correctly with close adherence to procedures. The NRC

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inspectors verified that QA personnel did observe performance of severel

i operational and maintenance work activities. The NRC inspectors' observations

I relating to the shift turnover briefings emphasize the need for operator atten-

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tiveness at all times.

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2.2 Quality Assurance and Control Activities

2.2.1 Inspection Results

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The NRC inspectors observed 0A activities, interviewed QA personnel, and l

reviewed applicable QA aud) ind surveillance reports in the operations area. 1

Specifically, the inspectors abserved quality control (QC) (a part of Quality

Department at Wolf Creek) involvement in maintenance and testing of reacto"

trip breakers and QA personnel performing a followup surveillance. The NRC

inspectors also reviewed audits and surveillance reports that involved opera- l

tions activities, as well as those covering general work control.

QA personnel audited noimal, backshift, and weekend activities and surveyed

operations activities. The NRC in @cctors observed that QA personnel were

knowledgeable and competent in the V audits and curveillances and maintained

an adequate mixture of direct QA uservation of operational activities and

review of documentation.

The NRC inspectors reviewed audit reports that spanned approximately 2 years.

The quality of the reports and types of observations had recently improved,

covering more of the actual performance of the activity rather than verifying

strict compliance to procedures. An essential elements book was written and

implemented by the QA department to ensure tnat the essential elements of test

procedures were critically analyzed by a QA auditor during his or her verifica-

tion activities.

The NRC inspectors observed that during the performance of maintenance on the

reactor trip breakers (Work Request 50762-88), QC personnel were present and

verified the completion of several in-process inspection hold points. In addi- '

tion, the NRC inspectors acccmaanied a QA inspector during a followup sur-

veillance of plant equipment, )oth safety related and nonsafety related, and of

general plant conditions. This surveillance was performed to verify that

corrective actions for deficiencies identified in QA audit TE53359 S-1627,

"Control of Plant Equipment," had been implemented.

During the followup surveillance, the licensee's QA inspector identified

several unacceptable conditions, including one that involved the storage of

safety-related snubbers in the auxiliary building. More specifically, approxi-

mately nine mechanical snubbers had been functionally tested in early May 1988

and three had failed. Although all nine of the snubbers were appropriately

tagged, the licensee did not segregate the failed snubbers from the snubbers

that passed testing. In addition, all nine snubbers were stacked together 19

an area not designated for storage. When the NRC inspector questioned the

acceptability and adequacy of this condition, licensee management had the

snubbers moved to a proper storage area used for safety-related equipment. The

licensee's QA inspector also identified a leaking valve on the second stage

feedwater reheater drain tank. This valve, AFV 944, is a level switch isola-

tion valve, and it contained a body-to-bonnet steam leak. The QA inspector

reported this condition and subsequently the valve was repaired with furmanite

to stop the leak. It was apparent to the NRC inspectors that the QA inspector

was knowledgeable of proper plant conditions and of the need to promptly report

result, to management.

The NRC inspectors also reviewed approximately 10 recent QA audit and sur-

veillance reports. One of these reports, QA Audit TE50140 K-192, "Corrective

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Actions," identified 0-rings in the solenoid oserators of post-accident

sampling system containment isolation valves tut were not environmentally

qualified (EQ). Licensee personnel discovered the 0-rings that were not EQ in

November 1987 during the implementation of a plant modification request

(PMR1844). This moJification involved changing valve solenoid springs in

several valves. During the implementation of PMR 1844, a maintenance crew

mistakenly disassembled the solenoid operator of a valve (GS-HV-013) not

requiring modification. The crew realized t!.eir error, and they also identi-

fied that the solenoid operator contained EPR-type 0-rings that were not EQ for

that specific application. Corrective work requests were written to inspect

the solenoid operators and to replace the EPR 0-rings that were not EQ with

EQ grafoil 0-rings, as necessary. The following valves were inspected: con-

tainment hydrogen control valves GS-HV-4, GS-HV-C GS-HV-9, SS-HV-13, GS-HV-14,

and GS-HV-10; nuclear sampling valves SJ-HV 3, SJ-HV-4, SJ-HV-5, and SJ-HV-128;

and steam generator blowdown valves BM-HV-35, BM-HV-06. BM-HV-37, and BM-HV-?a,

The QA organization issued a defect / deficiency report (D/DR 87-132) after

discovering that the 0-rings in the valves were not EQ. The QA organization

also issued a quality plant deviation (QPD) and a programmatic deficiency

report (PDR OP87-111) to address the disassembly of the wrong solenoid operator

during implementation of PMR 1844. An engineering evaluation (87-SJ-10) was

performed to determine the effect of having the 0-rings that were not EQ in the

valves. The results of the engineering evaluation showed that moisture or

water that might intrude into the solenoid operator if an 0-ring that was not

EQ failed would not affect the valve's pressure retaining function; however,

moisture could cause the valve to remain in the failed-closed position upon

receipt of a containment isolation signal and not allow the valve to reopen to

operate the post-accident sampling system. All of the work requests for the

affected valves had been completed at the time of the engineering evaluation.

It could not be determined how many of the 14 valves in question had contained

0-rings that were not EQ because the 0-rings in all valves were changed and the

licensee did not docu'nent which of the valves had the 0-rings that were not EQ.

The NRC inspectors determined that the valves were originally delivered with

EPR 0-rings that were not EQ, but were subsequentl

Package (OCP) CS-90-W, Field Change Work Request (y modified by Design Change

work permits CWP BM-212-E, CWP-GS-651 and work request WR698-85. At the time of

the QVFI, it was unclear whether the 0-rings had actually been replaced during

implementation of the work permits and request or whether additional work on

solenoid operator 0-rings had been performed on the valves after the original

issuance of the CWPs and WR. However, it is apparent that during the time when

FJ 603A-02 was issued and CWP BM-212-E, CWP-GS-651 and WR 698-85 were all com-

pleted by January 21, 1985, the maintenance organi::ation did not adequately

accomplish the specified activities and the QC organization failed to verify,

during their reviews and inspections, that the proper EQ 0-rings had been

installed. The licensee's actions to ensure that the deficient valve operators

had EQ 0-rings installed corrected the immediate problem. However, the NRC

inspectors detemined that the licensee had not investigated the underlying

cause which permitted installation of 0-rings that were not EQ to remain

installed in the solenoid operators. This failure to determine the

underlying cause of the conditiN is considered a potential enforcement finding

(Item No. 88-200-1a). This issue is also addressed in NRC RIV Inspection

Report 50-482/88-19 and will be followed up by Region IV.

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2.2.2 Results Sumary l

The NRC inspectors detennined that QA activities generally were conducted in a

performance-oriented manner by qualified individuals.

2.3 Operations Training

2.3.1 Inspaction Results

The NRC inspectors reviewed licensed, non-licensed, and craft training

practices. The NRC inspectors' interviews with instructors indicated that the

instructors were competent and professionally trained. Instructor performance

is evaluated by the manager of training as well as by seer, self, technical

peer, and supervisory personnel. Each instructor had )een appropriately

certified for the activities he or she was performing. There currently are

four positions for licensed instructors, two were filled by qualified contract

personnel, and two were vacant. The training staff and the instructional staff

appeared to be dedicated, professionally competent, and responsive to student

concerns and needs.

2.3.2 Results Sumury

The NRC inspectors were concerned that two vacancies in positions for licensed

instructors exists in the licensee's training department. This issue was

discussed with licensee management to emphasize the importance of training and

the need for a fully staffed training department.

3 PLANT MAINTENANCE

3.1 Maintenance Activities

3.1.1 Inspection Results '

The NRC inspectors observed maintenance activities on a pressurizer code safety

valve and a component cooling pump and evaluated the engineering support

activities for maintenance on a pressurizer spray valve. The inspectors

reviewed the following attributes of each maintenance activity: quality of

instructions and worker training, familiarity of worker with the task and with ~

tools and equipment, listing of task precautions, adherence to procedures, and

QC involvement in the activity.

3.1.1.1 Pressurizer Spray Valve

The NRC inspectors reviewed engineering calculations generated by Nuclear Plant

Engineering personnel in support of the encapsulation of a pressurizer spray

valve packing box. The encapsulation was necessary to control a reactor cool-

ant leak from the packing box assembly. The NRC inspectors determined that the

calculations were detailed and accurate. Engineering personnel performed a

thorough analysis that demonstrated good support of this maintenance activity.

3.1.1.2 Pressurizer Code Safety Valve

The NRC inspectors watched the maintenance technician set up and clean the

components on a pressurizer code safety valve in preparation for disassembly

and rework. The work was well organized and managed. The NRC inspectors also

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reviewed the applicable maintenance procedure to be used for this activity and

determined that the detail, references, precautions, tool requiremer. s, and

other important data were adequate. -

3.1.1.3 Component Cooling Water Pump Disassembly

The disassembly of the component cooling water (CCW) pump was a relatively com-

plex task that relied hea/ily on skill-of-the-craft. The work instruction con-

sisted of six general steps on the work request form and a reference to an

attached photocopy of a section of the pump vendor's manual. The procedure

used for disassembly was also photocopied from the pump vendor's manual.

During the work to remove the pump's bearing, the NRC inspectors observed that

the maintenance technician w6s using a bearing puller on the bearing while

heating the bearing housing with a gas flame torch. The technician involved

was knowledgeable of the process, but not of potential effects that heating

might have on the material characteristics of the bearing and pump shaft. No

method was .specified, nor was a contact thormometer on hand to determine the

temperature of the heated parts. The NRC inspectors noted that the instruction

to remove the bearing simply stated "remove the bearing." The work instruction

did not include a caution statement addressing the potentir' damage to the pump

shaft or bearing, heating instructions, expected temperature for bearing

release, or maximum temperature recomendations.

QC inspectors were not present during this activity because it was not con-

sidered a detailed step requiring a QC hold point. Apparently, the Quality

organization responsible for procedural reviews determined that this bearing

removal did not require additional details and that skill-of-the-craft was

adequate.

The NRC inspectors discussed the lack of temperature limits and a heating

process description and control with the procedure writing group in Maintenance

Engineering. In response, the engineering supervisor stopped maintenance

activities until the pump vendor could be consulted. Following consultation

with the vendor, a bearing surface temperature limit of 750'F was specified, an

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expected bearing release temperature of 300' to 500'F was established, and

heating process instructions were provided in a revision to the work request.

The revision also indicated methods for monitoring bearing and shaft

temperatures.

This CCW pump bearing removal activity indicated a weakness in the work process

with regard to the appropriatness and adequacy of crocedures and work instructions

and is considered a potential enforcement finding '(Item No. 88-200-2).

Additionally, the assumptiun that skill-of-the-craft was sufficient for this

i activity was not prudent and demonstrated poor comunication between procedure

writers and task performers (Observation Item No. 88-200-3).

3.1.2 Results Su mary

The NRC inspectors concluded that general maintenance technician performance

was good, QC presence during performance was adequate, mairtenance craft

knowledge and experience levels were adequate, but work instructions,

especially with regard to limitations and precautions, were weak.

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The NRC inspectors determined that the probable causes of the v:ork instruction

weaknesses were the informality of work inst uctions, unfamiliarity of pro-

cedure writers with the task to be performed, inadequate attention to detail, .

and a lack of feedback from maintenance personnel to cognizant enginesrs on

problems they encounter and recomendations to improve the instructions.

3.2 Control Building Heating, Ventilating, and Air Conditioning (HVAC) System

3.2.1 Inspection Results

From 1985 until now, the control room ventilation isolation signal (CRVIS)

system has been activated 72 times as a result of spurious signals from the

chlorine monitor system, and radiation detectors and other components in the

HVAC system. More specifically, 28 of the CRVIS actuations have been attributed

to malfunctions of the chlorine; monitor system and the remaining 44 to problems

with the radiation detection system, electrical circuit breakers and dampers

within the HVAC system. The following sections detail the inspector's review

of the three opparent contributors to the CRVIS actuations.

3.2.1.1 HVAC Breakers

The NRC inspectors reviewed records pertaining to problems with the control

building HVAC circuit breakers. In early 1985, the licensee's Maintenance

Engineering organization identified nuisance tripping of the HU-B100-0501 ITE

b/eakers at their respective motor control centers (MCC). An engineering

evaluation request (EER 85-GK-08) was prepared by Maintenance engineering

on July 2ti, 1985. The resulting engineering evaluation, complated on

November 27, 1985, stated that new breakers would be ordered with a specified

instantaneous trip setting.

The NRC inspectors determined that the licensee had received the breakers

ordered by engineering, but had never installed them in the designa+ed system.

Since the maintenance organization was not notified that the brea; vs had been

received, their work request records indicated that this item was open because

the parts were not available. The NRC inspectors determined that of the two

breakers ordered for this system, one was in the warehouse and the other had

been used in another system and not installed into the appropriate MCC as

specified in engineering disposition REDA 0-E-1324-GK. It appeared that no

one was tracking this item to ensure that the replacement breakers were

installed as directed by engineering. This failure to take the specified

corrective actions regarding the HVAC electrical system breakers malfunctions

is considered a potential enforcement finding (Item No. 88-200-lb). In

response to this issue, the licensee has committed to evaluate the existing

engineering evaluation request tracking system.

3.2.1.2 HVAC Dampers

The inspectors reviewed records pertaining to problems with the control build-

ing HVAC dampers. The records indk:ated that during routine work, maintenance

engineering personnel found that the HVAC dampers were not aligned as required

by the design drawing. Although Maintenance Engineering determined that the

observed misalignment was the cause of the damper failures, it was not evident

whether Maintenance Engineering considered the cause of the misalignment during

the investigation of the damper problem. Additionally, the investigation into

the cause of the failures did not consider whether the multiple CRVIS actuations

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also were contributing to the damper problem. These failures to fully

investigate the underlying causes of the multiple HVAC damper ftilures is

considered a potential enforcement finding (Item No. 88-200-1c). .

3.2.1.3 Control Room Habitability System Chlorine Monitors  !

The NRC inspectors reviewed the specification for the replacement chlorine

detector monitors that are part of the control room habitability systein and

verified that the site-suecific technical requirements for the monitors were

defined within the specification criteria. The NRC inspectors also reviewed

the engineering design calculations to ensure that the technical specification

requirements were considered when evaluating the new design criteria.

The chlorine monitors are essential elements of the control room habitability

systems. These habitability systems permit access to and occupancy of the

control room during normal plant operations as well as during and following

emergency conditions. They also are designed to enable the plant operators to

achieve and maintain the plant in a safe shutdown condition following a design-

basisaccident(DBA)

As discussed previously, the chlorine monitors have caused 28 actuations of the

control room ventilation isolation signal system (CRVIS) since 1985. Eighteen

of these actuations were due to paper tape problems, seven were due to signal

spikes from the chlorine monitors, and three were attributed to causes such as

manual actuation and personnel errors. Operations personnel currently are

required to survey the chlorine monitors twice per shift to look for indica-

tions of a possible malfunction.

The NRC inspectors reviewed a recent engineering study that had been conducted

to provide solutions to prevent further malfunction of the control room chlor-

ine monitoring system. This study indicated that the major problems with the

chlorine monitors were tape failures, electrical failuras, spurious spikes with

tape failures, and failures of lamps. The licensee recently issued a work

order to remove a WISA puma from its present location in the chlorine monitor

unit to a remote location )ecause the licensee believed that WISA pump vibra-

tions may have been contributing to the problems. The results of this modifi-

cation will not be known until sufficient operating time has elapsed.

l The licensee also plans to replace the 7040 MDA model monitor with a commercial

l grade Delta chlorine detector system during the next outage scheduled for the

lest quarter of 1988. The Delta system is to be dedicated and qualified during

l the third quarter of 1988. In addition, the licensee has ordered a Sensidyne

chlorine detector system to back up the Delta chlorine detector system. The

i

NRC inspectors determined that the licensee's activities to replace the present

MDA chlorine monitor system with Delta and Sensidyne systems were positive

actions to resolve the problem.

l

The liceqsee has experienced a large number of CRVIS actuations resulting from

'

the cMorine monitoring system malfunctions without aggressively pursuing

resolution of the problem until recently. Because of the large number of

CRVIS actuations attributed to chlorine monitor malfunctions since 1985 and the

, apparent slowness with which the licensee has taken action to correct the

l problem, this matter is considered a potential enforcement finding (item No.

I 88-200-1d).

I

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3.2.2 Results Summary

On the basis of the above, the licensee's program for determining the under- -

lying causes of plant system and component failures and malfunctions needs

strengthening. The fragmentation of responsibility for implementing the WCGS

corrective action program appears to be contributing to the program's weakness.

With the exception of maintenance technicians, no single organization has been

given the responsibility to technically analyze failures and malfunctions to

determine their underlying causes. Additionally, the licensee's investiga-

tions of component failures and malfunctions do not always consider their

effect on interrelated systems.

Without adequate cause evaluation information, thorough analysis of failures

and malfunctions cannot be made and the trending programs become merely failure

frequency indicators. Trending information should be used to increase the

reliability of plant systems through early detection of repetitive component

failures.

3.3 Maintenance Measuring and Test Equipment

3.3.1 Inspection Results

The NRC inspectors reviewed the QA activities associated with measuring and

testequipment(M&TE). The inspectors selected a review sample of M&TE used on

various maintenance activities to determine the adequacy of the out-of-tolerance

evaluations, of the historical documentation of M&TE use (use-history), and of

the QA corrective action process. Additionally, the inspectors reviewed 10

randomly-selected out-of-tolerance evaluations to verify timeliness and tech-

nical adequacy.

The NRC inspectors determined that, with one exception, out-of-tolerance

evaluations were performed in a timely manner and were technically adequate.

That exception, an evaluation for micrometer No. WC-6710, indicated that past

usage of the lost instrument was acceptable because the previous two annual

calibrations were within acceptable tolerances. In this case, better assurance

of the microreter's accuracy during previous use would have been provided by a

remeasurement of affected activities to verify if the previously taken meaure-

ments were within expected ranges. The inspectors considered the micrometer

example to be isolated.

3.3.2. Results Summary

The NRC inspectors determined that the measuring and test equipment program

adequately supports ongoing maintenance activities.

3.4 Fire Protection System

3.4.1 Inspection Results

The licensee has experienced a high instance of alarms activating as a result

of the malfunction of a specific type of microswitch u:;ed in the fire protec-

!

tion system. These microswitches are installed on various outdoor valves that

are located above and below ground. The Maintenance Engineering organization

issued EER 87-FR-06 on May 8, 1987, which stated that the present micro-

switches, Type PV IS-B, are routinely found corroded and are being used in

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applications for which they were not designed. The NRC inspectors reviewed 16

recent work requests associated with microswitch failures and found that the

microswitches continue to be misapplied. At the time of this inspection, the-

licensee had not taken action to stop using the microswitches in applications

for which they were not designed. This failure to take actions to resolve the

apparent misap

ment finding (plicaton of the microswitches is considered a potential enforce-

ItemNo.88-200-le).

3.4.2 Results Summary

The NRC inspectors determined that the fire protection system was adequate.

However, the inspectors were concerned that the control room alarms that

resulted from the malfunctioning microswitches may desensitize the operatnrs

to an actual fire protection system actuation.

3.5 Emergency Diesel Generator Vendor Service Information Letters

3.5.1 Inspection Results

The NRC inspectors reviewed several service information letters (SIls) to

determine whether proper evaluation and implementation of any necessary

component inspections and modifications had been performed by the licensee.

These SIls were issued by the emergency diesel generator (EDG) vendor, Colt

Industries, to convey vital service information to its customers.

During an interview, licensee personnel told the NRC inspectors that Colt SIls

are considered vendor technical information, which is to be reviewed and evalu-

ated under Wolf Creek's Industry Technical Information Program (ITIP). The

ITIP was established in response to NRC Generic Letter 83-28, Section 2.2.2.

However, when the NRC inspectors asked to review the evaluation of Colt SILs

conducted under the ITIP, licensee personnel gave the NRC inspectors an inter-

office memorandum (No. AD 87-0373) dated November 9, 1987, which stated that no

Colt SILs had been transmitted to ITIP personnel for their review and evalua-

tion because of miscommunications between the vendor (Colt), the plant's

architect-engineer (Bechtel), and licensee personnel. The memorandum also

requested that Colt be contacted to determine which SILs were applicable to

Wolf Creek and to send them for immediate review by ITIP personnel.

Colt determined that there were five SILs that pertained to the EDGs supplied

to the licensee. Licensee personnel stated that they had received the SIls from .

Colt in January 1988. However, at the time of this inspection, the NRC inspec-

tors found no formal review or evaluation of the five SILs had been performed

by the licensee. Further, the inspectors determined that the licensee had not

received three other SILs that pertained to the Wolf Creek EDGs. This failure

to obtain all relevant Colt Sils, review them to determine their applicability

to WCGS, and evaluate their relevance to the Wolf Creek EDGs is considered to ,

be a potential enforcement finding (Item No. 88-200-4). Subsequent to this

finding, the licensee issued Programmatic Deficiency Report OP-88-12a and

issued an engineering evaluaticn request to determine if additional Colt SIls,

which were applicable to Wolf Creek, existed and had not been received by

ITIP personnel.

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The NRC inspectors reviewed Colt SIL, Issue 7 (December 16,1985), entitled

"Intercooler Spacer Bar," to determine if information therein pertained to

the Wolf Creek EDGs. This SIL, which had not been received by the licensee, .

addressed a potential problem associated.with the spacer bar supporting the

side-mounted turbocharger intercoolers and noted that the spacer bar mounting

bolts should be periodically checked for tightness.

The NRC inspectors performed a field walkdown of the A and B EDG intercooler

supports and associated cooling water piping. During the walkdown, the inspec-

tors noted that all four turbocharger cooling water piping lines were missing a

seismic and vibration control pipe support that was required to be installed by

vendor's design drawings. In response to this observation, the licensee con-

tacted the vendor (Colt Industries) to determine if the turbocharger cooling

pipe could perform its intended function without the seismic and vibration

control supports and whether the turbocharger cooling pipe would experience

cracking or the flange bolts would loosen as a result of excessive vibration.

The vendor referred the licensee to Colt Industries' Engineering Report No.

M-018-0367-02, "Seismic Calculations.for Skid Mounted Piping." A table in this

report indicated that the support bracket would be required for the turbo-

charger cooling piping in a seismic event if the length of the piping was

greater than 60.7 inches. The licensee measured the subject piping and found

that it was 56 inches in length; thus concluding that the turbocharger cooling

pipe could perform its intended function during a seismic event without the

support bracket. The licensee gave the NRC inspectors a draft copy of their

engineering seismic calculation, which also indicated that the pipe did not

require the support to withstand seismic loading.

Even though the available engineering data did not support installation of the

supports for seismic reasons, Colt urged the licensee to install the four

missing supports to ensure that vibrations from the operating diesel engine

would not cause degradation of engine components. In addition, Colt

recommended that the licensee visually inspect the pipes for cracking and a

loss of jacket cooling water and perform a torque inspection for all associated

pipe flange bolts.

The licensee took imediate actions to fabricate and install the four pipe

supports and performed the inspections recommended by Colt. During those

inspections, quality control inspectors found that the turbocharger cooling

piping on the A EDG contained a weld defect. This item was referred to

engineering for further evaluation. In addition, when it was determined

the two of the flange bolts were torqued below minimum requirements, a work

request was issued to retorque all of the affected pipe flange bolts for both

emergency diesel engines. Before the conclusion of the inspection, the

'

licensee further comitted to perform nondestructive examinations on all four

turbocharger cooling water pipes and a vibration test and analysis to determine

if there were any additional adverse effects on the cooling pipe caused by

operating the EDGs without the supports.

At the time the EDGs were originally constructed at Wolf Creek, the turbocharger

cooling water piping vibration supports were not installed as required by

the vendor's design drawing. During the installation work, licensee personnel

who were res)onsible for verifying that the EDGs were properly constructed did

, not ensure t1at the supports had been installed. This failure to verify that

the as-built configuration of tne EDGs was consistent with the Colt design

'

drawing is a potential enforpement finding (Item No. 88-200-5).

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3.5.2 Results Sumary

The NRC inspectors identified several instances where the licensee did not -

obtain and evaluate all the applicable EDG vendor information (SILs). In part,

this contributed to the four missing pipe supports for the cooling water piping

lines not being discovered by the licensee. Although the supports were not

necessary for seismic support, the vendor did recommend that they be added for

vibration reasons. QC inspections of the EDGs during this inspection did

reveal that excessive EDG operational vibrations had caused the pipe flange

bolts to loosen to the point wht:re they did not meet torque requirements.

These issues point to the need for additional attention to detail in the area

of vendor interface.

3.6. Diesel Generator Jacket Water Pressure Transmitters

3.6.1 Inspection Results

The NRC inspectors performed a walkdown of the A and B EDGs and their associated

support systems. During the walkdown, the NRC inspectors noticed plant modifi-

cation reauest (PMR) Tag No. 20315, dated April 11, 1986, adjacent to the

jacket water pressure indicator gauge on the local control panel for the A EDG.

The information on the tag indicated that a pulse in the gauge's serising line

was causing a false indication on the pressure gauge. The NRC inspectors

went to the local control panel for the B EDG to determine if the same con-

dition existed. They saw two information tags located next to pressure gauges

for the jacket cooling water and the jacket water intercooler. Both informa-

tion tags indicated that there was a sensing line pulsation problem and that

the lines were valved out to isolate the system and stop spurious alarms in the

control room during system testing. The NRC inspectors asked a plant operator

if it was possible that the sensing line for the indicator gauge on the A EDG

was isolated even though there was no indication of such on the PMR tag. The

operator stated that the PMR tag did not serve that purpose and that the line

for the A EDG should not be isolated. However, when the NRC inspectors and the

operator examined the line, they found it had been valved out and isolated. In

response, the operator notified the SR0 on duty and replaced the PMR tag with

one containing the correct line configuration information. Because the

licensee took immediate action to correct the problem and because the line was

used for indication of system operating parameters, the inspectors have con-

sidered this issue adequately resolved.

The NRC inspectors interviewed cognizant instrumentation and control (I&C)

personnel to determine why the false indication conditions existed and what had

been done to correct the problem. Previously, a temporary modification was

implemented to install pressure damping devices in the sensing line. The

dempers alleviated the problem until they became clogged with impurities from

the jacket cooling water. Subsequentl The

licensee then initiated EER 87-KJ-01 (y, the dampers were removed. June 9, 1987) to

The EER contained information indicating that the problems with the pressure

transmitters resulted from pressure pulsations in the jacket water sensing line

side of the transmitter. In the disposition of the EER, Plant Engineering

recommended remounting the pressure transmitters and placing dampers or

similar flow restriction devices adjacent to the transmitter where the trans-

mitter sensing line ties into the pressure portion of the system. This

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modification, when implemented, will shorten the length of line between the

transmitter and damper and reduce the amount of impurities that could clog the

dampers. I&C personnel stated that, although this modification is planned, the

problem is still ongoing. The licensee has not to date considered the cause

of the pulsations ar.d the effect of the proposed corrective actions. This

failure to aggressively pursue the cause and take action to stop the sensing

line pulsations that have existed since 1986 is considered a potential enforce-

mentfinding(ItemNo. 88-200-1f).

3.6.2 Results Summery

The NRC inspectors determined that the licensee had not adequately addressed

the malfunctions in the jacket water pressure sensing line and instruments of

the EDGs. Since initial discovery of the problem in April 1986 to the time of

the QVFI, the licensee has not aggressively pursued the cause o.f the pulsations

in the system nor have they implemented timely, effective corrective actions to

ensure accurate and reliable system performance. Disregard of this instrument's

inability to perform its intended function is not an attribute of prudent, safe

operation of the EDG system.

4 INDEPENDENT SAFETY REVIEW ORGANIZATIONS

The NRC inspectors reviewed the activities of Wolf Creek's independent safety

review groups to determine their effectiveness and contribution to the plant's

safe and reliable operation.

4.1 Pla It Safety Review Comittee (PSRC)

'

4.1.1 Inspection Results

The NRC inspators reviewed the minutes of six PSRC meetings (306, 316, 317,

319, 320, and 322), interviewed selected personnel with regard to the PSRC

activities, and attended a PSRC meeting (No. 322) on June 14, 1988.

The PSRC function is specified by Procedure ADM 01-002, Revision 16, "Plant

Safety Review Committee." The procedure implements the requirements of Tech-

nical Specification 6.5.1, "Plant S. fety Review Comittee (PSRC)." The

PSRC reetings were conducted routinely at weekly intervals, which is more

frequently than required by the Technical Specifications. Additional meetings-

were scheduled when deemed appropriate. The QA manager, or a designated

alternate, normally attends the scheduled PSRC meetings, even though the QA

manager is not a member. -

The NRC inspectors determined that all but two of the selected PSRC members

had the experience and equivalent training normally required to take an exami-

nation for a senior reactor operator's license at Wolf Creek. The two PSRC

members with less exte.nsive training were the Manager of Maintenance and

Modifications and the Manager of Plant Support. The inspectors discussed

upgrading the training of these two managers with the licensee.

The NRC inspectors reviewed the materials discussed during the PSRC meeting

(322) conducted on June 14, 1988. During the meeting, plant modification

request PMR 02577, Revision 0, "Penetration Roundary Change," was reviewed,

l The PMR had been processed in response to corrective work request (VR 00688-88)

dated February 9,1988. The WR was written to ducument that the top 6 inches

14

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of Radflex material was missing from penetration OP 142S1099 located on eleva-

tion 2026' of the auxiliary building. The shift supervisor declared the

p netration operable on February 9, 1988. The initial review of the degraced.

condition of the sealant was completed on February 18, 1988, and resulted in

a "use-as-is" disposition of the WR. The basis for the use-as-is disposition

was that there was enough Radflex material remaining to allow sufficient fire

rating but not enough for a radiation barrier. As a result, the design of the

penetration seal was revised from an RB-9 type (Radflex) to an M-9 (fire seal).

The followup engineering disposition regarding the condition of the penetra-

tion was completed on May 3, 1988, and concluded that the floor at elevation

2026' separates fire area boundaries and requires a 3-hour fire-rated penetra-

tion seal. Because of the uncertainty of the current consistency of the

Radflex material in penetration OP 142S1099, engineering could not establish

that the penetration would meet these fire qualification testing requirements.

WCGS's Updated Safety Analysis Report (USAR), Section 9.5, Table 9.5.1-3,

requires that all fire barriers and their penetrations separating safety-

related areas from those that are not safety related or separating portfans

of redundant systems important'to safe shutdown shall be operable at all times.

Should one or more be found to be inoperable, a continuous fire watch on one

side of the affected barrier or an hourly fire watch patrol must be estab-

lished within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The inspectors discussed the May 3 engineering evalua-

tion and the degraded condition of the fire seal with the licensee. On June 14,

1988, the licensee issued Fire Protection Impairment Control Permit No.88-244

to establish a firewatch. In effect, a fire watch should have been established

within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from the time the fire seal was determined not to meet fire

qualification testing requirements. This failure to implement the required

fire watch between May 3 and June 14, 1988, is considered a potential enforce-

ment finding (Iter No. 88-200-6).

4.1.2 Results Summary

The NRC inspectors determined that, with the exception that a required fire:

watch for an unqualified penetration fire barrier was not established, the PSRC

function was established and functioning as required by Technical Spucifica-

tions.

4.2 Nuclear Safety Review Committee (NSRC)

4.2.1 Inspection Results

The NRC inspectors reviewed the minutes of NSRC meetings conducted in 1987 and

1988 and interviewed selected personnel with regard tr NSRC activities.

The NSRC function is specified by Policy No. II.13.0, Revision 3, "Nuclear

Smfety Review Committee Charter." The policy implements the requirements of

Technical Specification 6.5.2. Document reviews and discussions revealed that

the meetings were scheduled and conducted more frequently than required--

generally three or four times per year. NSRC meetings are routinels conducted

at the site training center and include a scheduled plant tour. Also, the

members can independently review specific areas of plant operations, such as

operations, chemistry, and health physics. The requirements of NSRC audits is

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addressed in detail, including overall responsibility, planning and implemen-

tation, audit reports, and resolution of findings. The audits and audit

results are maintained in an action item list, as reflected in the NSRC meetirig

minutes. l

1

4.2.2 Results Sumary

The NRC ins]ectors determined that the NSRC consisted of technically capable

personnel w1o fulfill the requirements of the Technical Specifications. The

NSRC has provided upper management with technically sound recomendations

concerning plant safety and reliability and are functioning as an effective

quality verification organization.

'

4.3 Nuclear Swfety Engineering (NSE)

4.3.1 Inspection Results

The NRC inspectors reviewed selected NSE reviews and evaluations to determine

the effectiveness of NSE as an independent quality verification organization.

The NSE function is specified by Procedure KP-750, Revision 0, "Statement of

Responsibilities Nuclear Safety Engineering." The procedure implements

Item I.B.1.2 of NRC N, REG-0737 Technical Specification 6.2.3, USAR Chapter

18.1.7.2, and outlines actions in response to NRC Generic Letter 83-028. NSE

performs surveillances of plant activities in accordance with the requirements

of Procedure KP-751, Revision 0, "Surveillance of WCGS Activities by Nuclear

Safety Engineering." The procedure provided definition, responsibilitiss, and

the scope of'the surveillance activitier for NSE.

The NSE also reviews almost all operational information concerning other

comercial nuclear power facilities. It routinely receives all reactor trip

data and is required to complete the independent review of all unscheduled

reactor trips before reactor restart if the trip was complicated by other

plant perturbations.

Recently, the NSRC requested NSE to investigate a 4-percent indicated decrease

in total reactor coolant system,(RCS) flow. NSE determined that an analysis

of the calibration data for the RCS narrow-range resistance temperature detec-

tors (RTDs), which were used to establish core enthalpy rise, was required

because an increase of 1.5 to 2.0'F had been identified. The review of the

RTD calibration data taken during the 1987 outage was compared to the data

taken during initial startup in 1985. The comparison indicated (1) a much

wider variation between the hot leg RTDs (but not exhibited between the cold

leg RTDs) and (2) a disparity between the hot leg and cold leg RTDs. The wider

variation exhibited by the hot leg RTDs and the disparity between the hot and

cold leg RTDs indicated that the hot leg RTDs output signals had drifted

differently

ture gradients than(and

the resultant

cold leg RTDs,

thermalpossibly)as a result of

stress experienced bythethesteep tempera-

hot leg RTDs

following a reactor trip (a large number of which occurred during the first and

second year of plant operation).

The licensee had implemented a number of actions to attempt to reduce the RTD

errors, including the Westinghouse error analysis methodology. These actions

resulted in a reduction in the RTD errors and an increase in the indicated

(calculated) RCS flow. However, the NRC inspectors were concerned that the

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routine use of the Westinghouse error analysis methodology (cross-calibration

of RTDs and development of correction factors) and the utilization of RTD

vendor supplied resistance (R) versus temperature (T) curves may not be con- .

servative, in that the RTDs at Wolf Creek (or any other ft cility which uses

such methodology) may never be calibrated to a known standard to ensure generic

senser drift does not occur during the 40-year lifetime of the plant. Wolf .

Creek does not use the RTDs installed in thermowells to calibrate, under  !

controlled conditions, the RTDs in the protection system (imersion-type RTDs).

These system RTDs have not been checked to a known standard, directly or

indirectly, since initial installation.

Items 7 and 8 ("Overtemperature Delta T" and "Overpower Delta T," respectively)

in Technical Specification 3/4.3.1, "Reactor Trip System Instrumentation,"

Table 4.3-1, specify that a channnel calibration is to be performed at least

once every 18 months. Technical Specification 1.5, "Channel Calibration,"

specifies in part that a channel calibration shall be adjusted, as necessary,

such that the channel responds within the required range and accuracy to known

values of input and shall encompass the entire channel including the sensors.

The methodology used to calibrate the RTDs does not include checking the

accuracy of the RTDs to known values of input (temperaturo). Shifts in the RTD

calibration curveRTD

out-of-tolerance mayoutput

not bevalues

detected in a timely

(Observation manner,

Item No. which ma88-200-7)y

. The NRC result in

inspectors discussed this matter with the licensee; it vill require further

NRC NRR staff review.

4.3.2 Results Sumary

The NRC inspectors determined that the NSE appeared to be an effective, tech-

nically-oriented organization. The NSE has provided management with extensive

and accurate assessments of plant issues, such as the RTD cross calibration

issue and the problems with the control room chlorine monitors.

5 INDUSTRY TECHNICAL INFORMATION PROGRA:4 (ITIP)

1

5.1 Inspection Results

The ITIP function is specified by Procedure KGP-1311, Revision 1, "Industry

Technical Information Program." The ITIP implements the licensee's response to

items addressed in NRC NUREG-0737, Item I.C.5, "Procedures for Feedback of

Operating Experience to Plant Staff."

The NRC inspectors reviewed evaluations of twelve ITIP items received by the

licensee, as well as selected monthly status reports, a recent QA audit report,

the most recent effectiveness review report, and Procedure KGP-1311. The

inspectors held discussions with selected licensee personnel wi6 h regard to

ITIP activities.

The NRC inspectors' review of the completed ITIP evaluations indicated that the

timeliness of the reviews had improved dramatically over the past 3 months.

The timeliness issue was previously identified in QA Audit Report TE:50140-K202,

dated March 23, 1988. The report specifically identified the lack of timeli-

ness of the initial evaluations, a significant backlog of items requiring

reviews, and the need to complete programatic changes expeditiously. The

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evaluation review times have recently decreased from months to days. Discuss-

ions revealed that che licensee was applying additional effort to decrease the

ITIP backlog and other programatic improvements have been completed. -

5.2 Results Sumary

The NRC ins)ectors determined that weaknesses noted by the licensee's QA organization

regarding t1e timeliness of reviews have recently improved. However, the

importance of evaluating industry information on plant equipment and components

in a timely way is necessary for reliable and safe operations. Section 3.5 of

this report provides details of the ramifications when the ITIP fails to

fulfill its required function. Other ITIP functions were implemented in

accordance with applicable WCGS procedures.

6 ACTIVITY / EVENT REVIEW

The NRC inspectors reviewed the effectiveness of the licensee's quality verifi-

cation organizations through the corrective actions associated with four

specific activities: (1) emergency service water pipe wall thinning, (2)

ra

pressurizer

leakage, and sp(4)y valve replacement

containment packing box, (3) reactor vessel head 0-ring

cooler A repair.

6.1 Emergency Service Water (ESW) Pipe Wall Thinning

6.1.1 Inspection Results

The NRC inspectors reviewed documents and interviewed licensee personnel with

regard to pipe wall thinning experienced in portions of the ESW system in 1985

during normal system operations. Pipe wall thinning appeared to be caused by

erosion / corrosion from combinations of elevated flow rates through throttled

butterfly valves and the configuration of the ESW system.

With the exception of several short outages resulting from equipment malfunc-

tions, the unit operated continuously until the comencement of the refueling

outage in September 1987. The NRC inspectors reviewed a number cf specific

activities related to the corrective actions associated with pipe wall thinning.

WorkRequest(WR) 00653-87 was issued on February 13, 1987,

fact that the ESW piping below valve EFV-058 (throttled butterfly valvedocumenting)the

was

less than the specified minimum pipe wall thickness of 0.328 inches in numerous

locations. The WR noted that the system was operable and the condition not

reportable per 10 CFR 50.72. The WR was forwarded to Nuclear Plant Engineering

(NPE for evaluation and an engineering disposition was provided on February 19,

1987, specifying that repair of the minimum wall for pipe spool piece 1-EF05-

S-005/142 should be re) aired per instructions in Plant Modification Request

(PMR) 1903. PMR 1903 1ad been used to repair train "B" of the ESW system

during the 1986 refueling outage. The weld overlay repair of the ESW piping

was subsequently performed during June 26 to July 1, 1987. The required

system leak test was performed on July 1,1987.

1987, the Nuclear Safety Engineering (NSE) group performed a surveil-

In May(SSR

lance 87-045) of selected activities associated with the ESW pipe minimum

wall thickness deficiency. A draft report of SSR 87-04S was provided to the

plant manager on May 14, 1987. In the draft, NSE noted that no justification

for continued operation had been provided regarding the thin-wall ESW system

piping in that the engineering evaluation request (EER) only addressed the

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final weld overlay repair condition. The NSRC chairman, made aware of the

issue by the NSE, also pursued the questionable condition of train A of the ESW

system. Independent calculations were also performed by the licensee's .

engineering staff that confirmed that the ESW did not meet all its design

requirements. Wolf Creek Updated Safety Analysis Report 0 SAR) S.ction

9.2.1.2.1.1 states that the ESW piping and valves are designed to the require-

ments of ASME Section III, Class 3. Section 9.2.1.2.1.1 of the USAR states

that the ESW is safety-related, is required to function following a Design

Basis Earthquake (DBA), and is required to achieve and rLaintain the plant in a

safe shutdown condition.

The report of SSR 87-045, dated June 4, 1987, identified three concerns regard-

ing the handling of minimum wall work requests, including (1) the operability

determination made by the shift supervisor, (2) availability of information to

operations, and (3) a defined program for handling pipe erosion. Their report

also stated that the current safety evaluation covers only the permanent repair

and not the justification for the continued operability of the component during

the interim period.

The NSRC, aware of the EWS wall thinning issue in May 1987 as a result of NSE

involvement, held discussions with plant management, including the Chief

Executive Officer (CE0), on June 2,1987. The NSRC Chairman was intimately

involved in the oral and written communications regardin

I

by the NSE surveillance (SSR 87-045, dated June 4,performed 1987)g the concerns raised

in mid-May

1 1987. On June 18 1987, the NSRC chairman established a special review group

(two consultants),to evaluate the ESW wall thinning matter. The issue was

discussed in detail in NSRC meeting 87-02, conducted on June 24 and 25,1987,

and specific recommendations were proviue; to the licensee's CEO by letter on

July 10, 1987 for consideration. The recommendations included the following:

(1) Further encourage and formalize the communications process between project

personnel in the area of nonconformance report (NCR) disposition and

implementation.

(2) Require a study and documentation of the lessons learned as a result of

this occurrence with ESW pipe wall thinning from February 1987 until the

repair is completed. Additionally, the CEO was provided a copy of the NSE

surveillance report of SSR 87-045, which could not be closed because

corrective actions have not been completed.

The licensee's CEO provided a draft letter on the subject to the three vice

presidents (engineering, quality, and nuclear operations) on July 28, 1987.

The draft letter addressed three matters regarding the "detert:Ination of

operability," including (1) the operations group responsibilities, (2) NPE

evaluations of nonconforming conditions, and (3) provision of the NPE evalu-

a+. ion to operations for reassessment.

Subsequently, plant Administrative Procedure ADM 08-212 and Engineering

Procedure KPN-314 were revised to provide an erosion / corrosion program and

here the system design

provide

functionnotification

is adverselyofaffected.

operations Operations by engineering

Order w(0P)87-110 was issued on

July 29, 1987, to instruct that all thin-wall piping problems would be docu-

mented by an NCR in accordance with the procedure. To enhance connunications

betwcen operations and engineering, engineering now attends work planning

reetings. Licensee personnel stated that they will, in the future, request

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temporary relief from ASME Section XI requirements from the NRC, when required, '

and provide technical justification for continued operation for each relief

request. NPE had responded to the NSE surveillance report (SSR 87-045) on .

February 2, 1988. Nuclear Operations had not responded at the time of this

inspection.

The NRC inspectors determined that the licensee's actions were inappropriate

immediately following the discovery of the degraded ESW piping on February 13,

1987. The engineering disposition completed on February 19, 1987, stated that

the degraded ESW pipe downstream of valve EFV 058 required repairs because it

did not meet ASME requirements and, therefore, may not be capable of performing

its specified safety functions. At this time, the licensee did not declare the

system inoperable and allowed it to remain inservice until repairs were begun

on June 26, 1987. Wolf Creek Technical Specification Limiting Condition for

Operation (LCO) 3.7.4 requires at least two independent ESW loops be operable.

In addition, with only one ESW loop operable, the inoperable ESW loop must be

restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the reactor must be in at least

hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

The licensee's failure to declare the ESW system inoperable and meet the

re'quirements of LC0 3.7.4 is considered a potential enforcement finding (Item

No. 88-200-8). This issue was previously discussed in Region IV Inspection

Report 87-15, dated July 22, 1987.

6.1.2 Results Sumary

The lack of timeliness and thoroughness of the operational response to the ESW

pipe wall thinning and the apparent lack of coordination between the plant

operations staff and the various technical support groups is considered a

significant weakness in the licensee's operability determination process.

This recurrance of a problem with ESW pipe wall thinning should have triggered

an immediate response by the licensee to declare the system inoperable and

procede with expeditious repairs to assure safe and reliable system operation.

6.2 Pressurizer Spray Valve Replacement Packing 3ox '

6.2.1 Ir.spection Results

The NRC inspectors reviewed the documented work activities associated with the

replacement of the pressurizer spray valve packing box. The work was completed

on December 29, 1987, in accordance with work request WR 00101-87, dated

January 1,1987, and ASME Section XI Plan No. RR-87-074, dated September 21,

1987.

The NRC inspectors reviewed documents and interviewed licensee personnel with

regard to the work completion review by the licensee for the pressurizer spray

valve packing box replacement on March 18, 1988. The ap3ropriate component

qualific& tion documentation, which was supposed to have )een part of the pro-

curement package from Wes inghouse, had not been received. As a result, the

licensee could not ensure that the assembly of the pressurizer spray valve

packing box met ASME Section XI requirements. The missing documents were the

required ASME Code Data Report, Certified Material Test Reports (CMTRs), and

nondestructive examination (NDEP reports. Even so, the plant was restarted in

late December 1987 with the ASME pressure boundary component of undetermired

quality installed in the reactor coolant system. Engineering analyses did wt

determine that the the component was acceptable and ASME Section XI relief .ws

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not.obtained until late May 1988 (WR 1285-88, dated March 17, 1988 completed on

May 24, 1988; and PMR 02535, dated April 25,1988).

The licensee initiated a Programmatic Deficiency Report (PDR MM 88-07, dated

April 18, 1988) documenting a deficiency with the pressurizer spray valve pack-

ing box. The Manager of Purchasing and Material Services was given the assign-

ment to coordinate and collect documentation of the completed actions in

response to the PDR. The PDR addressed the WCGS program and Westinghouse

procedure requirements and the immediate corrective actions to investigate the

apparent Westinghouse error in omitting the appropriate component qualification

documentation. In addition, a review of all ASME Code Section III documenta-

tion packages that had been received prior to installing an ASME Section III

boundary item was to be performed and the spare spray valve packir.g box

assembly procured at the same time as the installed component was to be

rejected. The cause of the issue was to be determined and corrective actions

to prevent its recurrence were to be performed. The NRC inspectors determined

that all but two of the actions were completed. The rescheduled completion

date for the open items was September 1, 1988.

The overall corrective actions included the review of other repair-replacement

work packages to ensure that no other nonconforming safety-related equipment

had been installed. This review revealed that 17 issues required comment

resolution. However, none of these issues were deemed by the licensee to

impact safety-related equipment operability.

The licensee plans to replace the nonconforming valve packing box assembly

during the next outage of sufficient duration and proper plant conditions to

permit replacement. The NRC inspectors concluded that the licensee's overall

corrective actions for this issue appeared to be extensive and acceptable.

6.2.2 Results Summary .

The licensee's failure to ensure that the spray valve packing box conformed to

ASME requirements before plant startup has been addressed in NRC Inspection-

Report 50-482/88-15. The licensee's actions taken once the deficiency was

identified were both timely and effective and should ensure that repetition

will not occur.

6.3 Reactor Vessel Head 0-Ring Leakage

'

6.3.1 Inspection Results

The NRC inspectors reviewed the documented activities associated with the

reactor vessel head 0-ring leakage event of December 26, 1987, through Janaury 21,

1988.

Leakage from the inner reactor vessel (RV) head 0-ring occurred on December 26,

1987, during plant startup after the scheduled refueling outage. The inner

0-ring leakoff path was isolated and the leakage system aligned to monitor the

outer 0-ring. Subsequently, additional leakage was detected when the leakoff

temperature from the outer 0-ring increased between January 19 and 21, 1988.

The reactor was cooled down and the RV head removed on January 26, 1988.

Between January 26 and February 2,1988, the RV head 0-ring seating area was

inspected and cleaned. The licencee determined that the RCS level was at too

21

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high a level during the previous RV head placement, allowing water to overflow

into the 0-ring channel and eventually leak into the leakage indication system.

On February 2,1988, the licensee commenced installation of the new 0-rings ,

with the RCS cool nt level between 12 and 39 inches below the RV flange level.

The RV head wat at and the RV studs imediately installed and torqued while

the RCS water letel was held at 39 inches below the RV flange. Subsequent RV

head 0-ring performance has been satisfactory.

The NRC inspectors determined by document review and interviews that corrective

actions associated with this event were extensive and included specific program

and procedure improvements. Further, the installation of a new RV water level

indication system during the next refueling outage was scheduled and should

improve the control of the RCS water level during outages.

6.3.2 Results Summary

The licensee's inattention to detail during the installation of the RV head

0-rings during the 1987 refueling outage resulted in a forced plant shutdown

as a result of leakage of reactor coolant past the 0-rings. The licensee's

maintenance staff did not provide quality workmanship and the quality verifi-

cation personnel involved did not identify the deficiencies, which would have

prevented the forced shutdown. (Reference NRC Inspection Report 50-482/88-04)

In addition, the removal and replacement of RV head 0-rings resulted in many

additional staff-rem exposure hours, which is a concern to the ALARA commitment

(as low as reasonably achievable). The additional stress placed on plant

personnel as well as systems and components as a result of the shutdown and

followup activities also is significant from a safety standpoint.

The NRC inspectors determined that the overall corrective actions taken by the

licensee regarding this matter appeared to be acceptable. These actions should

provide improved cleanliness controls associated with the RV head, adequately

inspected RV 0-rings, and an enhanced RCS water level indication system. The

RCS new water level indication system also will provide better control of the

RCS water level. ,

6.4 Containment Cooler A Repair

6.4.1 Inspection Results

The NRC inspectors reviewed documented work activity associated with the repair

of the A containment cooler to assess the work planning and the quality

assurance / quality control (QA/QC) involvement and conducted selected interviews

to provide an adequate understanding of the work plan and associated activities.

The A containment cooler leak was identified and a work request (WR 04105-87)

initiated on October 165 1987. The licensee conducted a substantial amount of

planning, repair selections, engineering, repair work, and testing during

October 20 to December 22, 1987. The repaired cooler was tested on December 1,

1987, the cooler support reinspected on December 14, 1987, and the cooler was

returned to service on December 15, 1987. The insulation was replaced on

December 18, 1987. The final maintenance review was performed by December 22,

1987, and the final quality review was complete on February 7,1988.

Subsequent review by the licensee in April 1988 of the completed work package

revealed two deficiencies: (1) no certified material test report from a

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qualified vendor was available for the brazing material used to repair the

coolercoilsand(2)repairstothetubesoftheheatexchangercoilwereper-

formed without a qualified brazing procedure and a procedure qualificatior. -

record for the base metal and thickness required. The specific deficiencies

were brought to the attention of engineering and the subsequent engineering

dispositions concluded that the items were acceptable. Programmatic deficiency

reports were v.-itten on May 26, 1988 (PDR OP 88-095, improper brazing

material), and April 29, 1988 (PDR OP 88-094, improper brazing procedure),

specifying corrective actions wt h completion verified as of May 27, 1988.

The corrective actions regarding the issuing of improper brazing material

appeared to be satisfactory. However, the NRC inspectors noted that the weld

data sheet (ADM08-300, Exhibit A) was initialed and dated by the weld engineer,

without realizing that the incorrect brazing procedure was specified. The weld

engineer routinely uses a desk-top procedure and checklist that are not part

of the applicable administrative procedure. The NRC inspectors discussed the

use of uncontrolled desk-top procedures and simple checklists with licensee

personnel.

Additionally, the quality control review required to signify agreement with

specified brazing requirements was initialed and dated on the weld data sheet

withcut ensuring the correct brazing procedure was specified. After the

inspectors discussed.this matter with the licensee, an additional PDR was

written on June 14, 1988 (PDR QC-88-011, QPS review of WR04105-87 failed to

identify the wrong brazing procedure was to be used in the field). The PDR

noted that a memorandum was written to all QC quality plant support personnel

reminding them what type of review is required by Procedure QP 12.1, paragraph

7.1.2, and that QF 12.1 is to be revised to enhance review process to clearly

state what documen,ts are to be reviewed.

6.4.2 Results Summary

The NRC inspectors determined that the corrective actions taken by the licensee

regarding the cooler repair appeared to be adequate. However, the NRC inspec-

tors concluded that the final maintenance and QC review to determine technical

adequacy and completeness of the package should have been completed before the

shift supervisor restored the system to service.

7. EXIT INTETJIEW

The NRC inspectors held meetings with licensee supervisory and management per-

sonnel periodically during the course of the inspection to discuss the status

of tne inspection. The NRC inspectors met with the licensee's representatives

. (19cluded in the list in Appendix A to this report) on June 17, 1988, to summar-

ize the inspection scope and findings end the to discuss the observations and

potential enforcement findings. Although proprietary material was reviewed

during the inspection, no proprietary material is contained in this report.

23

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, ,e 6 .

APPENDIX A

.

PERSONS CONTACTED

Wolf Creek Nuclear Operatir$g Corporation Personnel

• B. D. Withers, President

• F. T. Rhodes, Vice President Nuclear Operations

• R. M. Grant, Vice President Quality

• J. A. Bailey, Vice President Engineering and Technical Services

• C. D. Boyer, Plant Manager

• C. E. Parry, Manager-Quality Assurance

• G. W. Reeves, Manager-Quality Contr?1

• W. M. Lindsay, Manager-Quality Eva'.sation

• R. H. Belote, Manager-Nuclear Safety Engineering

• J. M. Pippin, Manager-Nuclear Plant Engineering

• A. A. Freitag, Manager-Nuclear Plant Engineer-W.C.

• R. W. Holloway, Manager-Maintenance and Modification

• M. G. Williams, Manager-Plant Support

• 0. L. Maynard, Manager-Licensing

• S. Wideman, Licensing

• K. Peterson, Supervisor-Licensing

• J. A. Zell, Manager-Training

• C. W. Fowler, Manager-ISC

• R. J. Potter, Manager-Material / Supplier Quality

• W. B. Wood, General Counsel

• J. L. Houghton, Supervisor Operations

• M. L. Johnson, Nuclear Coordinator-KG&E

• W. B. Norton, Supervisor Reactor Engineering

• L. Payne, Supervisor Quality Plant Support

• R. E. Gimple, Supervisor Materials Quality

• C. G. Patrick, Supervisor Quality Systems

• C. J. Hoch, Quality Assurance Technician

R. S. Benedict, Manager Plant Inspection

R. S. Robinson, Supervisor, I&C Maintenance

W. G. Eales, Jr., Manager Electrical Systems Engineering

N. Hoadley, Lead Engineer, Nuclear Plant Engineering

A. Clason, Manager Engineering Support

T. Deddens. Outage Manager

L. Stevens, Lead Engineer Nuclear Plant Engineering

Other licensee employees contacted included operators, engineers, auditors,

technicians, mechanics, and office personnel.

NRC Personnel

• F. C. Hawkins, Chief, Quality Operations Section, NRR

• P. W. O'Connor, Project Manager, NRR

• J. Jaudon, Deputy Director, Division of Reactor Safety, RIV

• B. Bartlett, Wolf Creek Senior Resident Inspector, RIV

M. E. Skow, Wolf Creek Resident Inspector, RIV

• B. Little, Callaway Senior Resident Inspector, RIII

• Denote those attending the exit meeting on June 17, 1988

.