ML20214R404

Insp Rept 50-289/86-14 on 860825-0905.Major Areas Inspected: Operations,Design Changes & Mods,Maint,Safety Review Activities & Surveillance Testing.Six Potential Enforcement Findings,Referred to as Unresolved Items,Identified

ML20214R404
Person / Time
Site:	Three Mile Island
Issue date:	10/27/1986
From:	Chaudhary S, Dyer J, Howell A, Klingler G, Mckee P, Pierson R, Sharkey J, James Smith, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE)
To:
Shared Package
ML20214R389	List: ML20214R387 ML20214R404
References
50-289-86-14, NUDOCS 8612050458
Download: ML20214R404 (24)

See also: IR 05000289/1986014

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OFFICE OF INSPECTION AND ENFORCEMENT

DIVISION OF INSPECTION PROGRAMS

Report No.: 50-289/86-14

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Licensee: General Public Utilities Nuclear Corporation

P. O. Box 480

Middletown, Pennsylvania 17057

Docket No.: 50-289 License No.: DPR-50

Facility Name: Three Mile Island, Unit 1

Inspection Conducted: August 25, 1986 - September 5, 1986

Inspectors: IN #-2 3 -E

d. E. Dyer,' Inspection Specialist, IE Date

Team Leader

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J/D. Smith,InspectionSpecialist,IE

/o a/-B(,

Date

-(- \0-tab

R. C. Pierson, Inspection Specialist. IE Date

6kkav & /o-es-rc

S. K. Ehaudhary, Senior Reactor Engineer, Date

/C-4 -86

A. T. Ho ll, Inspection Specialist, IE Date

0.I alu

G.R.Kli'ngler,ReactorfperationsEngineer,IE

to -LMt.

Date

h t' h e Y $ < /O ~22.-24,

D. C. Trimble, Resident Inspector, Region I Date

/e-/6 24

. M. Sharkey, Ihstection Specialist, IE Date

Accompanying Personnel: *L. J. Callan, IE; *J. O. Thoma, NRR; *T. M. Ross, NRR;

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• A. R. Blough, RI; *R. Conte SRI, TMI-1; *D. Johnson,

RI, THI-1; *F. Young, RI, TMI-1; and *J. Rogers, RI,

. - TMI-1.

Approved by: / b

• Phillip F.fcKee, Chief

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l Operating Keactor Programs Branch, IE

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( * Attended Exit Meeting

8612050458 861106

l PDR ADOCK 05000289

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Scope:

A special, announced inspection was performed of the licensee's management

controls over the following functional areas:

• Operations

• Design Changes and Modifications

• Maintenance

• Safety Review Activities

• Surveillance Testing

Results:

The team determined that the management controls for licensed activities in

the five functional areas inspected at TMI-1 were generally adequate. However,

six potential enforcement findings, referred to as unresolved items in the

report, will be followed up by NRC Region I.

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1 INSPECTION OBJECTIVE

The objective of this team inspection was to evaluate the effectiveness of

management controls established to conduct licensed activities. This inspection

fulfills the requirement of Comission Memorandum and Order CLI-85-09, which

lifted the 1979 Shutdown Order on TMI-1 and directed, in part, that a Performance

Appraisal Team (PAT) inspection be conducted after 12 months of operation.

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The inspection effort covered licensed activities in the following five

functional areas:

• Operations

• Design Changes and Modifications

• Maintenance

• Safety Review Activities

• Surveillance Testing

The inspectors interviewed responsible personnel, observed activities, and

reviewed selected records and documents in each functional area to detemine

whether:

(1) The licensee had written policies, procedures, or instructions to provide-

management controls in the subject area.

(2) The policies, procedures, and instructions were adequate to ensure com-

pliance with regulatory and internal requirements.

(3) The licensee personnel who had responsibilities in the subject areas

understood their responsibilities and were adequately qualified, trained,

and retrained to perform their responsibilities.

(4) The requirements of the subject area had been implemented and appropriately

documented in accordance with management policy.

The specific findings in each area are presented as observations that the j

inspectors believe to be of sufficient importance to be considered in a

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subsequent evaluation of the licensee's performance. Some observations may  :

be potential enforcement findings. These observations, referred to as  !

unresolved items, were presented to the NRC Region I for followup.

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! 2 SUMMARY OF SIGNIFfCANT FINDINGS

The more significant findings pertaining to the management controls of licensed

activities at TMI-1 are summarized below. Although some programatic strengths

were identified in the areas of Operations, Maintenance, and Surveillance

Testing, the following summary focuses on the significant weaknesses identified

during the inspection. Section 3 provides detailed findings, strengths and

weaknesses in each of the five functional areas reviewed during the inspection.

l The observation numbers in parenthesis after the inditidual sumary items are

l provided for reference to the corresponding discussion in Section 3.

2.1 Operator Reviews

The following deficiencies were identified through reviews conducted in the

control room:

(1) Three instances were identified where safety system valve lineups did not

have the required signatures indicating completed reviews. (3.1.4)

(2) One instance was identified where the incorrect revision of a valve

lineup procedure was used despite the fact that the supervisory reviews

were conducted. (3.1.4)

(3) Six instances were identified where errors in manual calculations of

quadrant power tilt and core power imbalance went unnoticed through

senior reactor operator and shift technical advisor reviews. These

errors were identified during operations management reviews, three days

after they were performed. (3.1.2)

(4) Three instances were identified where manual heat balance calculations

were not reviewed until 3 days after they were perfomed. There were no

errors in these calculations. (3.1.2) ,

2.2 Drawing Contro1 __

The team identified the following problems with the implementation of the

drawing control prcgram:

(1) The licensee used hard copy drawings inside the protected area to control

plant operations. All drawings reviewed were the current revision.

However, Safety-Related Drawing, 302-082, " Emergency Feedwater System "

Revision 8, did not reflect the as-built configuration of the plant.

Drawing 302-082

did not reflect that motor-operated block valves EF-V 53,

54, and 55 were electrically disconnected or that check valve EF-V3 had

its internals renoved. (3.2.4)

(2) The licensee used aperture card drawings outside the protected area and at

GPUNC.

The Computer Assisted Records and Information Retrieval System

(CARIRS) was used to verify that the aperture cards were current. Of the

12 reviewed aperture card drawings, 6 were the incorrect revision. Further,

one of the six out of-date aperture cards was identified as being the

correct revision on the CARIRS. This combination of inaccuracies presented

the potential for use of out-of-date drawings in design and maintenance

activities. The root cause for this problem appeared to be delays in

updating the drawings and the CARIRS data base. (3.2.4)

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2.3. Post-Modification Testing of Remote Shu down Panels (RSPs)

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Major modifications to the RSPs were planned for the next outage and only a

functional check of the new RSP components and circuitry was planned at the

time of the inspection. The modifications included adding a third panel

to the existing two panels and adding instrumentation for control'of the ,

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emergency feedwater system, decay heat removal system, pressurized dump

isolation to the main condenser, normal makeup water system, and pressurizer  ;

power-operated relief valve'(PORV) block valve. The tean was concerned that f

the functional tests would not adequately demonstrate the operation of the '

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system and that an integrated test should be considered. (5.2.5) l

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2.4 Deficient Procedures '

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The team identified instances where procedures were improperly, classified as

not important to safety (NITS); consequently these procedJreS'did not receive

the required technical and safety reviews. Technical weaknesies also were  ;

identified with procedures.

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(1) Several procedures issued by the Technical Functions Division were

improperly classified as NITS and thereby did not receiv'e required

technical or safety reviews. The following are examples of irportant- -

.to-safety (ITS) activities that were governed by these procedures:

(3.4.1)

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' minor modification development

• design verification

• field change development -

• drawing revisions

In addition to being improperly classified, the procedure controlling the

plant engineering modification process was found to be technically weak.

(3.2.3)

(2) Of 20 special temporary procedures (STPs) reviewed by the team, 3 were

improperly classified. These STPs, which controlled special evolutions

in the plant during power operations, received a technical review, but

were not evaluated to determine if they created an unreviewed safety

question. All three of the improperly chssified procedures appeared to

have technical deficiencies. Conservative action taken by the operators

< during implementation prevented potential problems. (3.4.1).

(3) Although properly classified, two temporary change notices l(TCNs) to

station procedures were technically deficient:

l (a) TCN 86-95 to Procedure 1102-4, " Power Operations " provided guidance

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. for controlling small power excursions above the steady-state licensed

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power limit that were less conservative than NRC guidance. No

! examples were found where the licensee had exceeded the NRC guidance.

(3.1.3)

(b) TCN 86-112 to Procedure M-148, " Hydrogen Recombiner Lubrication /

Inspection," directed the mixing of lubricants with different chemical

i bases in the blower motors. This was contrary to environmental

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qualification (EQ) requirements. Maintenance personnel flushed the

residual grease out of the blower motor although this was not required

by procedure. (3.3.3)

2.5 Responsible Technical Reviewer (RTR) Knowledge

The RTRs were the individuals responsible for perfoming technical and safety

reviews of proposed changes to plant procedures, tests, and systems before

implementation. RTRs were used at TMI-1 instead of the onsite review comittee.

Interviews with RTRs revealed the following knowledge deficiencies:

(1) The depth and scope of the reviews' required by the Technical Specifications

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(TS) were not clear to all RTRs. (3.4.3)

(2) Several RTRs were unable to use the CARIRS. The CARIRS was identified as

a primary means for determining which documents were considered as licensing

basis' documents during reviews. (3.4.3)

(3) Some RTRs were not knowledgeable about the equipment included in the

environmental qualification (EQ) program or the importance of maintenance

actions for this equipment. (3.3.3) .

2.6 Safety Review Process

During the inspection, the licensee implemented a revision to its safety review '

L procedure which appeared to conflict with the requirements of the TMI-1 TS. l

The TS required reviews of all proposed changes to procedures, tests, and

systems classified as ITS, including a written determination of whether the

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proposed change constituted an unreviewed safety question. The revised

procedure added a screening step to the process that eliminated the written

determination for some procedures classified ITS. The 10 CFR 50.59 safety

evaluation performed for this revised procedure did not discuss whether the

proposed change would require a change to the TS. (3.4.2)

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3 DETAILED FINDINGS

3.I' Operations

The team reviewed the licensee's program for ensuring safe plant operation.

The review concentrated on the conduct of operations in the control room and

included a revie,t of the technical adequacy and implementation of selected

operating procedures.

3.1.1 Control Room Operations ,

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The team _-observed the control of ^various plant evolutions conducted during the

inspection,(reviewed logs and completed procedure documentation, and inter- ,

viewed shift operators. The following observations were made:

(1) Access to the control room was well regulated', particularly'near the

operating panels. Background noise was kept to a minimum and the

operators were very attentive to plant conditions. Operators who were

interviewed were knowledgeable about the overall status of systems and

the various evolutions occurring in the plant.

(2) Comunications appeared to be effective between operators and between

the operators and outside personnel. The team was particularly impressed

with the coordination and control exhibited during corrective maintenance

activities on the integrated control system (ICS). This maintenance

activity required taking manual control'of the ICS at three stations and

coordinating control of the plant until the ICS could be returned to

automatic operation. The operators performed this task in a very

controlled manner and communicated information on the various plant

parameters and coordinated power controlling actions at the stations.

(3) The licensee had achieved a relatively low number of alarmed control room

annunciators during power operation. During steady-state operating

conditions, the team observed only three alarmed annunciators.

3.1.2 Manual Calculation Review

The team reviewed the manual calculations of power distribution parameters

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required by TS and performed by the operators during the period from June 27

through July 1,1986 when the plant computer was out of service. The

following weaknesses were identified:

(1) Operators had made errors in F cf ;he 36 calculations reviewed that were

performed in accordance with ihr w al Procedure 1203-7, " Hand Calculations

for Quadrant Power Tilt ud An iwer Imbalance," Revision 18. These

errors did not result in u.y h 4.oiits being exceeded; however, they had

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gone undetected through the senior reactor operator and shift technical

advisor reviews. Operations management subsequently identified and

corrected the problems during their reviews 3 days after the calculations

were performed.

(2) Calculations performed in accordance with Procedure 1103-16. " Heat Balance

Calculations," Revision 16, were not reviewed by a reactor operator or

senior reactor operator until operations management pointed out the

deficiency during their review, 3 days after the calculation was

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performed. The team reviewed the calculation and found no errors with

the original calculation.

The team was. concerned that these deficiencies were examples of poor reviews

by the senior reactor operators and shift technical advisers. Interviews with

reviewing personnel revealed that they were knowledgeable about the manual

calculations and their responsibilities for review. The team emphasized to

licensee management that, in view of how infrequently these calculations were

performed manually, a more timely and careful review of the results would be

warranted.

3.1.3 Operating Procedures

The team reviewed selected operating procedures and found them to be technically

adequate in all but one case. The exception was Procedure 1102-4, " Power

Operations," Revision 40, which inadequately described how to maintain core

thermal power at the licensed steady-state limit. Temporary Change Notice

(TCN) 86-95 to Procedure 1102-4 revised the guidance for maintaining steady-

state power limits based on an August 22, 1980 NRC memorandum. The NRC

memorandum recognized that load fluctuations causing power oscillations

above the 100% steady-state limit were permissible up to 102% for 15 minutes,

101% for 30 minutes,100.5% for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, etc., as long as 102% power was never

exceeded and the average power level for an 8-hour shift did not exceed the

100% steady-state licensed limit. The operating guidance provided by TCN

86-95 did not require action upon reaching the stay times for power levels

between 100% and 102% of the steady-state limit and could allow power opera-

tions beyond the permissible excursions identified in the NRC memorandum. The

team reviewed the station power history and confirmed that the licensee had not

exceeded their steady-state licensed limit as defined in the NRC guidance. ,

3.1.4 Valve Lineups

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The team reviewed completed valve lineup sheets for nuclear safety-related and

important-to-safety systems and identified the following weaknesses:

(1) Independent verification of valve lineups were not documented for the -

following systen lineup procedures:

• Procedure 1104-5, " Reactor Building Spray System," performed

April 1986.

• Procedure 1104-4, " Decay Heat Removal System," perfomed on

April 16, 1986.

" Procedure 1104-11. " Nuclear Service Closed Cooling Water Systems,"

performed April 1986.

Further review revealed that, at the time these lineups were performed,

the licensee was not required to perforn independent verification of

these systems. The team detemined that the licensee had previously

committed to the NRC to expand the scope of its independent verification

program by January 1987. The details of this expanded program were still

under development at the time of the inspection and not available for the

team to review. NRC Region I was following the licensee's comitment as

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l Unresolved Item 50-289/85-27-08 and will review the expanded program at

. implementation.

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(2) All review signoffs were not completed for the following safety system

lineups:

• Procedure 1104-4, " Decay Heat Removal System," completed on April 16,

1986, had no review signatures. ,

' Procedure 1104-1, " Core Flooding System" (enclosure 1), completed on

April 17, 1986, did not have the second management review signature

on the valve checklist.

(3) The latest procedure revision was not used for Procedure 1104-4, " Decay

Heat Removal System," which was completed on April 20, 1986.  :

The apparent failure by the licensee to follow procedures for performing the

required reviews and implementing the correct revision of valve lineup

procedures will remain unresolved pending followup by the NRC Region I  :

(289/86-14-01).  !

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3.2 Design Changes and Modifications *

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The team reviewed the licensee's program for the development, installation, t

and closeout of design change packages. This included a review of the program  ;

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for accomplishing major plant modifications and the expedited processes for '

accomplishing modifications of lesser magnitude under the Mini-Mod and Plant

Engineering Modification Programs. Additionally, the team reviewed the i

licensee's overall program for drawing control. Unlike the Performance ,

Appraisal Team (PAT)/ Safety System Functional Inspection (SSFI) conducted

during March 3-27, 1986 (Inspection Report No. 50-289/86-03), this inspection

did not include detailed engineering analyses of selected design changes;

rather, the emphasis of this inspection was on the licensee's design change

program and . processes.

3.2.1 Plant Modifications

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Plant modifications were those design changes' engineered by the Technical

Functions Division at GPUNC. Since the PAT /SSFI inspection conducted during

March 1986, the licensee had made a considerable effort to improve its plant

modification program by revising its governing procedures and by conducting

training of responsible personnel on the new procedures and the overall

regulatory requirements for design change control. The team determined that

j the revised procedures adequately complied with the licensee's regulatory

commitments. Interviews revealed that responsible engineering personnel were

knowledgeable about the revised procedures and regulatory guidance. However,

the revised procedures had not been implemented on any plant modification

packages that were available for the team to review.

3.2.2 Plant " Mini-Mods"

Plant mini-mods were those modifications engineered by the onsite Technical

Functions Group. The Mini-Mod program expedited the design change process for

those plant modifications that did not require detailed engineering analyses

and were within the capabilities of the Technical Functions personnel on site.

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The team reviewed the selection criteria and overall control process outlined

in Procedure EMP-002, " Mini-Mods," Revision 0, and detemined that it adequately

complied with the licensee's regulatory comitments. The team reviewed the

following mini-mods:

• A25A-53150 123150, "Seis'mic Mount on Control Room Console for

Neutron Flux Recorder"

• A25A-53151 123200, "Retube of Make-up Air for RM-42 Sample Pump"

• A25A-53166 123166, " Miscellaneous Electrical Work"

The modification selection, design analyses, and safety reviews appeared

adequately implemented for these modifications.

3.2.3 Plant Engineering Modifications

Plant engineering modifications were those design changes engineered by station

plant engineers. These included minor equipment modifications and changes

classified as " replacement-in-kind." The team reviewed Procedure EMP-019,

" Plant Modifications Engineered by Plant Engineering," Revision 0, and its

implementation and identified the following weaknesses:

(1) The criteria for defining component " replacement-in-kind" appeared to

be too broad. Procedure EMP-019 allowed ". . . replacement of wornout or

failed equipment with a similar component that does not change the overall

function or performance of that equipment." This could allow substitution

of functionally equivalent components without adequate design control.

Specifically, Procedure EMP-019 did not provide a systematic process by

which nameplate data for replacement-in-kind components were evaluated

for conformance to all the required design specifications. Interviews

with plant engineering personnel revealed that this evaluation of

performance criteria was left to the discretion of the reviewing engineer

and relied significantly upon that individual's experience to perform an

adequate evaluation. The team was concerned that the cumulative effects

on a safety system by replacing functionally equivalent components with

slightly different performance characteristics could degrade the overall

ability of the system to function.

(2) The testing conducted after a plant engineering modification was not

required to be reviewed by the plant engineering personnel who developed

the modification. Station maintenance personnel accomplished the modifi-

cation and conducted the testing. The completed tests and modification

packages were not required to be reviewed by plant engineering personnel

before closecut to verify that the modified equipment was operating as

intended.

(3) A review of selected plant engineering modifications revealed that the

supporting rationale for some of the modifications appeared weak. For

example, Plant Engineering Modification 85-279-M allowed the replacement-

in-kind of the original aluminum seat with a machined brass insert in

all the Fisher Series 3500 valve positioners throughout the plant. The

engineering evaluation stated that this work did not create a seismic

concern and did not constitute an unreviewed safety question. However,

the'se assertions were not substantiated in the evaluation and the various

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locations and uses of the Fisher Series 3560 positioners were not listed

or evaluated for the modification. This appears to be a case of inadequate

design analyses and will remain unresolved pending followup by the NRC

Region I (289/86-14-02).

3.2.4 Drawing Control

The licensee controlled station drawings by two methods as described in Procedure

1001C, " Drawing

Utilization," Distribution

Revision 2. Control," Revision 5, and Procedure 1001H, " Drawing

In the first method, controlled hard copies of

selected drawings were maintained at various locations inside the protected

area.

These hard copies were maintained current by the Drawing Distribution

Control Center (DDCC) and did not require verification before use. In the

second method, drawings were maintained on aperture cards outside the protected

area and at GPUNC and did require verification before use for important-to-safety

activities. The Computer Assisted Records and Infonnation Retrieval System

(CARIRS) was used for this status verification, and outstanding drawing changes

could be obtained from DDCC on site or at GPUNC to update the aperture card

drawings.

.The team reviewed the status of 12 drawings at four locations inside the protected

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area, on the aperture cards at the onsite DDCC, and as identified on the CARIRS

data base.

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Hard copy drawings reviewed in the Control Room, Technical Support

Center Instrumentation and Control (I&C) Maintenance Shop, and Electrical

Maintenance Shop were all found to be correct. Of the 12 aperture card "

drawings reviewed at the DDCC, 6 were not the current revision and 1 of these

drawings was listed incorrectly in the CARIRS data base. Consequently, a user

of Safety-Related Drawing SS-209-655, "RC Pump Monitor Rack Outline," would

have been misled by the CARIRS into believing that Revision 2 of the aperture

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card was current, when actually Revision 3 was the current revision.

The team also identified discrepancies between the current revision of a

controllsd drawing and the'as-built configuration of the station. Safety-

~ Related Drawing 302-082, " Emergency Feedwater," Revision 8, did not reflect

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that motor-operated block valves EF-V53, 54, and 55 were electrically disconnected

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or that check valve EF-V3 had its internals removed. Interviews with station

operators revealed that they were aware of these changes; however, the drawings

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As previously identified in PAT /SSFI Inspection Report No. 50-289/86-03, U

CARIRS

status. generally appeared to be an ineffective system for verifying drawing -

When a DDCC operator used CARIRS at the request of the inspection

team to verify the status of recently revised drawings, problems were encountered  ;

with each of the first three drawings checked. The assistance of the Manager, j

Technical

these problems. Functions-Site, and additional DDCC operators was required to resolve

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problems identified regarding the use of CARIRS for verifying drawing status

was the significant time lag involved before CARIRS and aperture cards were {;

updated to reflect design changes. Specifically, it required approximately

2-3 months to obtain updated aperture cards an

status to be updated after a change notice was.d uj to 2 weeks for the CARIRS

issued to revise a drawing.

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During this interim period before the CARIRS was updated, station or GPUNC l

personnel, prcperly following procedures, could incorrectly determine that a

drawing was current and acceptable for use when, in fact, it was out of date.

The licensee stated that it was aware of the drawing update backlog and had '

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already initiated action to reduce the backlog by increasing its drafting

resources.

The team was concerned that inaccuracies in controlled drawings, delays in

updating aperture card drawings, and problems identified with the CARIRS could

result in incorrect drawings being used for safety-related activities in the

plant. This item will remain unresolved pending following by the NRC Region I

, (50-289/86-14-03).

3.2.5 Remote Shutdown Panel Modifications -

The team reviewed the licensees plans for modifying the remote shutdown panels

(RSPs) during the next outage. The existing configuration consisted of two

separate, independent safety-grade panels, RSP-A and RSP-B. The instrumentation

and controls on these panels were limited and required operations personnel to

be stationed at numerous plant locations for remote plant shutdown. The

planned modifications consisted of adding a third panel (designated Auxiliary

RSP-B) and additional instrumentation and controls to the existing panels

(RSP-A&B), including controls for emergency feedwater. control to the once-

through steam generator (OTSG), decay heat removal system, pressurized dump

isolation to the main condenser, normal makeup water system, and pressurizer

power-operated relief valve (PORV) block valve. Interviews with licensee ..

management revealed that current plans were to perform only functional tests

of individual components and circuitry to demonstrate the capability of modified

remote shutdown panels. The team was concerned that these functional tests

would not provide adequate assurance of the ability of the operators to control

the plant from these panels.

At the exit meeting, licensee management representatives stated that the

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decision to conduct only functional tests of components and circuitry was based

on an engineering assessment of what would be necessary to verify proper design,

but that further testing was being considered. The licensee expressed concerns

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that conducting an integrated test would unnecessarily place the plant at risk.

However, the licensee acknowledged that a suitable integrated test could be

performed before criticality after the outage, thereby minimizing the perceived

risk to the plant. This item will remain unresolved pending followup by the

NRC Region I (289/86-14-04).

3.3 Maintenance

The team reviewed the licensee's programs for corrective maintenance, preventive

maintenance, and control of vendor manuals. Additionally, tours of the station

were made by the team to assess plant cleanliness and material condition.

3.3.1 Corrective Maintenance

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-Station corrective maintenance was accomplished using a job ticket program

that provided input to a machinery history program as described in Procedure

1407-1, " General Corrective Maintenance Procedure," Revision 27. The team

found this procedure to be adequate and the maintenance department personnel

who were interviewed were knowledgeable in all aspects of the program. The

corrective maintenance program generally appeared to be well managed as evidenced  :

by the following observations:

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~, .(1) Seven corrective maintenance procedures were reviewed for technical

adequacy.- All procedures appeared sound and, where appropriate, vendor

technical manual maintenance recommendations were incorporated into the

procedures.-

(2) Twenty-six ITS corrective maintenance job tickets were reviewed to

! determine if work had been perfonned in accordance with the administrative .

guidance in Procedure 1407-1. The team noted that repair procedures were '

used when appropriate, resolution descriptions were sufficiently documented,

drawings and manuels were updated when necessary,~and post-maintenance

testing was adequately conducted.

m (3) Corrective maintenance job tickets were prioritized and appeared to be

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aggressively managed to reduce the backlog of outstanding work requests.

Since plant startup (approximately 1 year ago), the number of outstanding

corrective maintenance work requests has been reduced from 600 to 300.

3.3.2 Preventive Maintenance

The preventive maintenance program used a computerized schedule to accomplish

periodic maintenance requirements as described in Procedure 1027, " Preventive

Maintenance," Revision 16. Additionally, the licensee quarterly reviewed the .

'

. output from the machinery history trending program to determine improvements

for the program as described in Procedure 1407-3, " Assessment of the Adequacy

of the Preventive Maintenance Program," Revision 2. The team considered this

overall program a strength and found the maintenance department personnel

responsible for the preventive maintenance program to be very knowledgeable in

>

all aspects of the program. The implementation of the preventive maintenance

program appeared adequate as evidenced by the following observations:

!

,

(1) The backlog of outstanding preventive maintenance items was small and

required outage conditions to be performed. Those items that were

.

overdue had been identified by the licensee, evaluated as acceptable,

i

and scheduled for accomplishment at the next outage.

,

(2) Recently completed preventive maintenance actions on the decay heat

removal and instrument air systems were reviewed. The team noted that

correct procedures were used and work was properly documented for the

l pumps, compressors, air dryers, and electrical breakers being maintained.

(3) The team verified that the preventive maintenance requirements were

properly updated to reflect new equipment installed as the result of

plant modifications. No deficiencies were identified with the changes

required for the three modifications reviewed.

3.3.3 Control of Environmentally Qualified (EQ) Equipment

4 The team developed a concern about the licensee's program for maintenance of EQ

l equipment. This concern was based on the maintenance activities reviewed for

! the hydrogen recombiner blower motors. On July 17, 1986, Temporary Change

1 Notice (TCN)86-112 was issued to authorize the use of UNIREX 2 grease

instead of the AND0K B grease specified by Procedure M-148, " Hydrogen Recombiner

'

Lubrication / Inspection," Revision 3. This TCH was approved and the UNIREX 2

grease was added to the blower motors for both hydrogen recombiners. Investi-

I

gation into this issue by the team revealed the following:

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(1) The licensee did not have the vendor manual for the hydrogen recombiner i

blower motor and consequently could not detemine whether the vendor

manual prohibited the use of UNIREX 2 grease. A subsequent engineering

'

evaluation perfomed by the licensee revealed that UNIREX 2 was a suitable

substitu~te.

(2) Although AND0K B and UNIREX 2 are environmentally qualified greases, each

has a different chemical base. Before the inspection the licensee

contacted the grease manufacturer regarding the generic acceptability

~

i of substituting UNIREX 2 for AND0K B and was told that the mixture could

not be approved. Although the maintenance documentation for this activity

indicated that the greases were mixed, interviews with maintenance

department personnel responsible for the lubrication of the blower motor

revealed that the motors were flushed of the old AND0K B grease when the

'

UNIREX 2 grease was added. This appeared contrary to Procedure M-148 and

TCN 86-112, which only specified adding two ounces of grease to the blower

motors.

(3) Interviews with maintenance department personnel and responsible technical

'

reviewers (RTRs) who were responsible for the review and approval of

lubrication procedures revealed a lack of knowledge about the EQ program.

Some maintenance personnel stated that they did not know that changing -

grease could affect the EQ status of the equipment. The RTR who perfomed

the TCN review did not realize the hydrogen recombiner was EQ equipment.

In general, both groups demonstrated poor knowledge of EQ maintenance

requirements and admitted that they had received very little training on

the subject.

Based on the above evidence, it appears that the environmental qualification

of the hydrogen recombiners was maintained; however, the team was concerned

that the deficiencies with technical documentation, adequacy of reviews, and

overall knowledge of the EQ program identified in this one instance could

cause problems with other EQ equipment during maintenance activities.

3.3.4 Vendor Manual Control

i

The licensee's program for control of vendor manuals was scheduled for com-

pletion in 1988. In the interim those uncontrolled vendor manuals used for

maintenance of ITS equipment were required to be evaluated by engineering to

determine their adequacy as described in Procedure 1065, " Vendor Document

Control," Revision 1. The team found this program generally to be adequate;

[ however, the following weaknesses were identified with the implementation of

,

the vendor manual control program:

(1) Controlled and uncontrolled copies of the same vendor manual were kept '

I together by the maintenance department. The potential for an uncontrolled

and incomplete vendor manual to be issued was increased by this practice.

I however, the team did not find any instances where this problem had

>

occurred.

(2) Two examples were noted where safety-related equipment was calibrated

using uncontrolled vendor manuals without prior engineering evaluations.

Two Bailey Meter multiplier modules were calibrated using an uncontrolled

manual " Bailey Meter (Multiplier)," E92-12, under Surveillance Procedure

1302-5.26 "0TSG Level Channel Calibration," Revision 4, accomplished

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• '

.,

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. in June 1985. Additionally, on April 8,1986 a Bailey signal monitor

4 was adjusted using an uncontrolled manual " Bailey Signal Monitor," E92-4,

1 under Surveillance Procedure 1302-5.18 "Hi and Low Pressure Injection

Flow Channel," Revision 10. In both cases the uncontrolled vendor manuals

were later evaluated as the correct guidance so the instruments were

properly calibrated.

1

Although the vendor manuals were subsequently determined to have provided the

,

correct guidance, these examples represent an apparent failure to follow

i

Procedure 1065. This item will remain unresolved pending followup by the NRC

'

RegionI(289/86-14-01).

,

3.3.5 Plant Material Condition and Cleanliness

The team assessed the plant's raterial condition and cleanliness by reviewing

the adequacy of the dispositioning of "use-as-is" material nonconformance

'

reports (MNCR), conducting plant tours, and reviewing the licensee's house-

keeping inspection program. The team found the plant material condition and

cleanliness generally were satisfactory as evidenced by the following observations:

(1) Administrative Procedure 1000-ADM-7215.01, "GPUN Material Nonconformance

r Reports and Receipt Deficiency Notices," Revision 1, defines in part -

"use-as-is" as a material disposition that means the material, part, or

component that is the subject of the MNCR is acceptable for unrestricted

use in its present condition. For 1986, six maintenance department

MNCRs fell into the "use-as-is" category. Four of the six had not yet

been dispositioned, but had been forwarded to Technical Functions for

engineering evaluations in accordance with the procedure. The remaining

i two MNCRs had been closed out. The engineering reviews that were

documented in Section 4 of the MNCRs appeared adequate and were well

documented.

'

(2) Plant tours by the team revealed no plant cleanliness problems. Addi-

tionally, the licensee has a program described in Procedure 1008, " Good

"

Housekeeping," Revision 14, where inspections are conducted and their

deficiencies dispositioned monthly. This program appears to have been

aggressively implemented.

! 3.4 Safety Review Activities

The team revibwed the safety review process as applied to proposed plant

modifications, tests and procedure changes in accordance with the requirements

.

of TS 6.5 and 10 CFR 50.59. As described in TS 6.5, the licensee's review

I process is different from that described in the Standard Technical Specifica-

l tions in that one person reviews are pemitted instead of the comittee reviews.

l The responsible technical reviewer (RTR) performs the reviews normally assigned

, to the onsite review comittee while the Independent Safety Reviewer (ISR)

. performs the offsite committee review functions. The licensee's program also

'

is unusual in that TS 6.5 expands the scope for required reviews to include

i all activities and modifications that are classified as ITS.

l

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'

During the inspection, the licensee revised its procedure for conducting safety

reviews. The team reviewed the implementation of the old process described in

,

Corporate Procedure 1000-ADM-1291.01, " Nuclear Safety Reviews and Approvals at

TMI-1 and Oyster Creek," Revision 0-01, and the adequacy of the new process

l

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as described in Corporate Procedure 1000-ADM-1291.01, Revision 2. Additionally,

the QA oversight of the program and the qualifications, knowledge level, and

training of RTRs were reviewed. ,

3.4.1' Safety Review Process Implementation

The team reviewed the implementation of the safety review process for tests

and procedures as described in Corporate Procedure 1000-ADM-1291.01, " Nuclear

Safety Reviews and Approvals at TMI-1 and Oyster Creek," Revision 0-01. This

procedure described a process where written safety evaluations were conducted

for all proposed changes classified as ITS. These evaluations were then

reviewed by the RTR and the ISR before the procedure was issued. TS 6.5.2.5

only required ISR review of written safety evaluations for changes to procedures

as described in the FSAR. ISR reviews were not required by TS to be performed

before a change was implemented. The licensee's procedural requirement for a

second ISR review before issuance of all ITS procedures was beyond the TS

requirements and imposed by licensee initiative. During this inspection, the

following problems were identified with the classification and technical

adequacy of the procedures:

(1) The following station special temporary procedures (STPs) provided

guidance for ITS activities and were apparently incorrectly classified

as not important to safety (NITS):

• STP 1-86-001, " Flush of MU-V-140" - This procedure flushed a check '

valve in the makeup and purification system and admitted demineralized

water to the reactor coolant system during power operations.

• STP 1-86-014. " PAT Team Data EFP-1" - This procedure tested the

steam driven emergency feedwater pump during power operations.

• STP 1-86-015, " Dilution of IC System" - This procedure involved

partial draining of the intermediate cooling (IC) system during

power operations. The IC system supplied cooling to important

loads required for plant operations such as reactor coolant pumps,

j letdown heat exchangers, and control rod drive motors.

The 3 improperly classified STPs were identified from a sample of 20 STPs

reviewed by the team. STPs were essentially new procedures issued for a

temporary time period. Those STPs, classified as NITS, still received an

RTR technical adequacy review in accordance with Procedure 1001A,

" Procedure Review and Approval," Revision 11, but were not evaluated for

constituting an unreviewed safety question. The team was concerned that

by improperly classifying STPs as NITS the licensee was not performing

adequate safety reviews of its procedures.

! (2) The following technical functions procedures described _ ITS activities and

were apparently incorrectly classified as NITS:

l * Procedure EMP-2, " Mini-Mods," Revision 0-00, which described the

design chan

mini mods (ge see control

section process

3.2.2) for plant modifications classified as

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l

' * Procedure EMP-19, " Plant Modifications Engineered by the Plant,"  !

Revision 0-00, which described the design change control process I

forplantengineeringmodifications(seesection3.2.3)

• Procedure EP-9, " Design Verification," Revision 2, which described

the requirements for checking modification package analyses

• Procedure EP-25 "As Built Drawings," Revision 2, which described

how station drawings were controlled and updated after system

modification

• Procedure EMP-15. " Field Questionnaires, Change Notices, and Change

Requests," Revision 2, which described how to change a design

modification package during the construction phase of accomplishment

The above examples are only representative of several improperly classified

technical functions procedures for the control of the design change and

drawing control processes. This appears contrary to the definition of

ITS in the licensee's Quality Assurance Plan which includes activities

described in 10 CFR 50, Appendix B. Unlike the STPs, technical function

procedures were not required to receive RTR reviews. Interviews with

licensee management revealed that QA reviewed these procedures, but this

QA review did not necessarily satisfy the TS 6.5 review requirements.

(3) The following procedures had technical inadequacies: ..

• STP 1-86-001, " Flush of MUV-140," did not remove the flushing rig

from the system or restore the makeup and purification system

demineralizers to their normal lineup. Licensee personnel performing

the flush removed the flushing rig and restored the system to its

normal operating lineup.

• STP 1-86-014 " PAT Team Data EFP-1," required that a check valve

(MS-V-69) be verified open and mislabled a steam trap. These

errors did not impact the conduct of the test.

• STP 1-86-015. " Dilution of IC System," permitted the expansion

. tank level to be reduced to the engineered safeguards actuation *

!

system (ESAS) low-level set point. Low expansion tank level coincident

I

'

with a high-pressure injection signal would cause partial IC system

isolation and potential loss of cooling to the reactor coolant

i

'

pumps. This could compound a plant casualty. However, operators

performing the flush acted conservatively and stopped draining the

expansion tank before reaching the low-level ESAS set point.

• TCN 86-95 to Procedure 1102-4 for power operations incorrectly

translated NRC guidance into operating guidance (see Section 3.1.3).

The guidance of this TCN was less conservative than that provided

by the NRC regarding actions required for small power excursions

j above the licensed power limit.

l

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• TCN 86-112 to Procedure M-148 improperly pennitted the mixing of .

greases with different chemical bases in environmentally qualified

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?

equipment (seeSection3.3.3). Maintenance personnel acted con-

servatively and flushed the residual grease from the motor although

it was not required by procedure.

• Procedure EMP-019 did not provide adequate guidance for the evaluation

of replacement-in-kind modifications. The procedure did not require

a systematic review of component performance characteristics to ensure

that ertinent design criteria were being maintained (see Section

3.2.3 .

In the cases cited above, conservative actions on the part of the main-  ;

i

tenance and operations personnel performing the activities prevented  !

possible plant problems. The team is concerned that relying on personnel I

to identify and correct procedural deficiencies is not a sound practice

and could lead to procedural compliance problems.

The team was concerned that the safety review process for procedures as described

in Corporate Procedure 1000-ADM-1291.01, Revision 0-01, and implemented by the

plant and technical functions organizations was not consistently ensuring

that adequate procedures were being issued. This concern was previously raised

by NRC Region I during the most recent Systematic Assessment of Licensee -

'

Performance (SALO) Report (50-289/85-97). It appeared that the licensee's

requirement for RTR and ISR reviews before implementation of ITS procedures

,

created delays in the process that were unacceptable to the plant and technical

functions orga~izations. n Consequently, short cuts were taken by improperly

classifying procedures or providing cursory reviews that did not identify

, potential problems with individual procedural steps or restoration activities.

'

'

The' apparent failure by the licensee to properly classify procedures and conduct

adequate reviews will remain unresolved pending followup by the NRC Region I

(289/86-14-05).

3.4.2 Revised Safety Review Process

4

The new process for safety reviews implemented by Revision 2 of Corporate

Procedure 1000-ADM-1291.01 on September 1, 1986 added a screening step to the

process. The screening step had the effect of eliminating written safety

determinations for some changes to ITS procedures. Instead, a simple yes/no

check mark on a form was substituted for the written determination. Conse-

i quently, the questions in 10 CFR 50.59 comprising the definition of an

l unreviewed safety question were not directly answered in the new screening

step and there was no bases documented for the detennination. It appears

that this change to the safety review process conflicts with the intent of

TS 6.5.1.12, which required that reviewers render determinations in writing

whether proposed procedures, and changes thereto, classified as ITS constituted

an unreviewed safety question. The licensee was not required to conduct

. committee reviews of proposed changes. Instead, safety evaluations were one-

! person reviews, making it very important that the reviews be exceptionally

'

thorough. Interviews with licensee management revealed that this screening

step would reduce the number of written safety evaluations and result in a

more efficient process and allow procedure changes to be implemented more

, expeditiously.

!

The safety evaluation for Corporate Procedure 1000-ADM-1291.01, Revision 2,

t

failed to address the potential for the change to conflict with TS 6.5.1.12

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and appeared to be an inadequate 10 CFR 50.59 evaluation. This issue will

remain unresolved pending followup by the NRC Region I (289/86-14-06).

3.4.3 Responsible Technical Reviewer (RTR)

The RTR was responsible for the in line review of procedures, tests, and plant

modifications for safety and technical adequacy before implementation as

described in TS 6.5 and Corporate Procedure 1000-ADM-1291.01. The RTRs who

,

' were interviewed were generally knowledgeable and had received training in

August 1986 to prepare them for implementation of the new review process.

However, the interviews revealed the following weaknesses with the training.

>

and knowledge of the RTRs:

(1) The depth of the required reviews were not clear to all RTRs. Although

the August 1986 training program and Revision 2 to Corporate Procedure

1000-ADM-1291.01 described the technical review as a " verification of

the technical and safety adequacy of a document" and a " thorough review

!

from a technical standpoint . . .", one RTR indicated that the training

,

program was not clear regarding the extent of technical review required.

A manager-level RTR stated that depth of review varied with procedures

based upon his judgment of the significance of the change.

.

(2) The scope of the required reviews were not clear to all RTRs. RTRs were

expected to be sufficiently knowledgeable of licensing basis documents

so that they could detennine if procedure changes " require revision of

,

any procedural or operating description in the FSAR or otherwise require

revision of the TS or any other licensing basis document." Even the

senior RTRs were unable to identify all doct'nents forming this licensing

'

basis. One RTR considered the basis to be oaly the FSAR and TS.

!

(3) Some RTRs as well as other onsite personnel did not have a working

knowledge of the CARIRS. CARIRS was described by licensee management

as the principal data base for identifying licensing basis documents.

(4) One RTR failed to recognize EQ requirements associated with a TCN that

changed the type lubricant used for hydrogen recombiner blower motors

4

(see Section 3.3.3). No checklist existed to remind RTRs of items to

} look for, such as EQ requirements.

(5) One RTR had received very little training in reactor theory.

Because the TMI-I TS only require one-person reviews, it is imperative that

.

the RTRs be sufficiently knowledgeable to recognize potential problems and to

know when to seek additional reviews for areas outside their field of expertise.

The RTRs also should have a clear understanding of the depth and scope of the

.!

required reviews. The above examples indicate that several qualified RTRs may

-

not have this knowledge and understanding. -

3.4.4 Management Oversight of the Review Process

The licensee had several mechanisms for reviewing and enhancing the adequacy

of its review process. These included a QA monitoring program, the Procedure

4

,

Review Group (PRG), and the Procedure Compliance Task Group (PCTG). Specific

'

improvements initiated by these oversight activities included:

1

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(1) The QA monitoring program had challenged the technical adequacy and

the NITS classifications of procedures on numerous occasions. The

apparent misclassification of STP 1-86-001 was challenged in report

SCD-0124A-85 as well as the technical adequacy of the procedure.

However,' these issues had not been resolved by the licensee.

(2) The PRG was a multidisciplined comittee of the senior RTRs that met

approximately twice weekly to review the more complex procedural issues.

This group provided a collegial review missing from the program outlined

by the TS.

i (3) The PCTG was made up of senior management personnel who were to review

the root causes of procedure-compliance problems, including the adequacy

of procedures within all of GPUNC. During the inspection, the PCTG

report was being finalized and reviewed by senior GPUNC managers for the

appropriateness of recommended corrective actions. The report appeared

to be a thorough review of the problems within GPUNC.

3.5 Surveillance Testing

The team reviewed the licensee's TS surveillance programs. This review included

the processes for scheduling, accomplishing, and recording individual surveil -

lances; implementing changes to the technical procedures; and the overall

management of the programs. The team did not review TS surveillance testing

for radiological environmental monitoring equipment that was covered by a

separate program.

The TS surveillance program included testing of all systems and equipment

specifically identified in the TS (except radiological monitoring surveillances)

and the calibration of those instruments required to adequately perfom the

TS surveillance tests. The program was adequately described in Procedure 1001J,

" Technical Specification Surveillance Program," Revision 6. This procedure

established a process which used a matrix to cross reference procedures and TS

requirements, computer assisted scheduling, weekly status reviews of activities

by management, and line management review of completed tests. This process

generally was considered to be a strength.

The team reviewed 30 completed surveillance tests and found no discrepancies

with the technical adequacy of the procedures, data obtained from the tests

or the timeliness of reviews of completed tests. However, two minor weaknesses

were identified:

(1) Surveillance Procedure 1303-11.45, "PORY Setpoint Check " was performed

on June 25, 1986 using Revision 6 of the procedure instead of Revision 7

which became effective June 21, 1986. The cause for this apparent

discrepancy was that the procedure became " effective" imediately upon

approval without allowing time for the procedure to be printed and

distributed. This process took approximately 1 week; during the

interim, the list of effective procedures would not reflect the issued

procedures. The team reviewed the differences between Revisions 6 and 7

of Procedure 1303-11.45 and detemined that there were no changes that

affected the test results. Additionally, the licensee had previously

identified this problem and was in the process of changing its procedures

for issuance so that both the approval date and effective date of a

procedure would be indi:ated.

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(2) Surveillance Procedure 1302-6, " Calibration of Non-Tech Spec Instruments

used for Tech Spec Compliance," Revision 21, was not updated to reflect

the transfer of instrument calibration responsibilities of three instruments

to the Measuring and Test Equipment (M&TE) Calibration Program. Table I

of Procedure 1302-6 listed all instruments to be calibrated; according

to the procedure, this table was used to prepare a computerized matrix for

scheduling calibrations. The team found that three instruments listed

on Table I were not on the computerized schedule. Further review revealed

that calibration responsibilities for these instruments were recently

transferred to the M&TE program and.the computer schedule was updated to

reflect the change but not the governing procedure. The team reviewed

the M&TE calibration schedule and found that the affected instruments

were calibrated on schedule.

These two examples of weak procedures did not result in any implementation

problems affecting the conduct of plant operation; however, the team was

concerned that these examples indicated a lack of attention to detail with

respect to procedure adherence.

.

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4 MANAGEMENT EXIT MEETING

4

An exit meeting was conducted on September 5, 1986 at the Three Mile Island,

Unit 1 Nuclear Station. The licensee's representatives at this meeting are

identified in the attached appendix. The following NRC management representa-

tives also were in attendance: P. F. McKee, Chief, Operating Reactor Programs

Branch, Office of Inspection and Enforcement (IE); L. J. Callan, Chief,

Performance Appraisal Section IE; and A. R. Blough, Chief, Reactor Projects

Section IA, Region I. The scope of the inspection was discussed and the

licensee was informed that the inspection would continue with further

'

in-office data review and analysis by team members. The licensee also was

informed that some observations could become potential enforcement findings.

, The observations were presented for each of the five functional areas

inspected and the team members responded to questions from licensee

representatives.

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APPENDIX

?

PERSONS CONTACTED

The following is a list of persons contacted during this inspection. There i

were other technical and administrative personnel who also were contacted.

All personnel listed are GPUNC employees unless otherwise noted.

• H. Hukil1 - Director. TMI-1

R. Long - Vice President, Nuclear Assurance Division

• R. Toole - Director, Operations and Maintenance, TMI-1

• N. Kazanas - Director, Engineering Projects

• R. Keaton - Director, Quality Assurance

J. Thorpe - Director, Licensing and Regulatory Affairs GPUNC

D. Slear - Director, Engineering Services

• M. Ross - Director, Plant Operations

• C. Smyth - Manager, Licensing

(M. Nelson - Manager, Nuclear Safety

• J. Fornicola - Manager TMI QA Modifications / Operations

B. Ballard - Manager TMI QA Modifications / Operations .

D. Shovlin - Manager, Plant Maintenance

R. Markowski - Manager, QA Programs / Audits

R. Gemann - Manager, Nuclear Safety GPUNC

• C. Hartman -Manager,PlantEngineering,TMI-1(E&IC)

.. ,

R. Barley - Manager, Plant Engineering, TMI-1 (MECH)  !

M. Snyder - Manager, Preventive Maintenance

L. Wickas - Manager, Operations QA

R. Harbin - Manager, Vender Document Control

R. Wulf - Manager, TMI Projects

D. Fultenberg - Manager, THI-1 Long Range Planning I

P. Moor - Manager, TMI-1 Projects

F. Barbieri - Manager, Secondary Plant

R. Harding - Manager, Quality Classification / Engineering Configuration

J. Flynn - Manager, Engineering Procedures and Standards

D. Shivas - Manager, Engineering Data and Configuration Control

T. Hawk' ins - Manager, Startup and Test, THI-1

R. Neveling - Manager, Document Distribution Control Center TMI

• C. Shorts - Manager, Technical Functions - Site

l *R. McGoey - Manager, PWR Licensing GPUNC

l R. Boyer - Shift Supervisor, Operations

! D. A. Smith - Shift Supervisor, Operations

D. E. Smith - Shift Supervisor, Operations

S. Sanfor - Supervisor, Configuration Control

• H. Wilson - Supervisor, Preventive Maintenance

• C. Incorvati - Supervisor, THI-1 QA Audits

R. Troutman - Maintenance Planning and Scheduling

G. West - Computer Supervisor

W. Frasier - Shift Foreman, Operations

D. Hoss - Shift Foreman, Operations

M. Bezille - Shift Foreman, Operations

A-1

i

_. . - - _ _ _ _ _ _ , . . _ _ , - _ _ - - _ _ _ . _ _ _ _ . - . , _ _ _ _ _ _ _ _ . . . _ , . _ _ _ _ . . . , _ - , . . _ . - - _ _ _ , . . . -

- .

,, ,- '".

, G. Davis - Shift Foreman, Operations

D. Neland- - Control Room Operator

'

J. Auger - Licensing Engineer

B. Gan - Project Engineer. TMI-1

D. Distel - Licensing Engineer

S. Ku - Secondary Plant Engineer

C. Brumbach - Maintenance, Construction and Facility -

L. Lanese - Safety Analysis and Plant Control

R. Summers - Lead Mechanical Engineer

, *D. Hassler - Licensing Engineer

• P. Sinegar - Administrator Plant Maintenance, TMI-1

T. Sinunons - Corrective Maintenance Assistant

D. Pilsatz - Document Distribution Control Center, TMI

D. Langan - QA Lead Auditor

D. Carl - Senior Technical Analyst

S. Wilkerson - Lead Nuclear Engineer

D. Atherholt - Engineer, Plant Operations

R. Eich - Technical Analyst, GMS Coordinator

T. Dunn - Operations QA

P. Wells - Safety Review Engineer

H. Shipman - Senior Engineer, Operations

C. Sertz - Senior Engineer -

G. Hoek - Control Room Operator

,

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J. Gallagher - Control Room Operator ,

J. Moore - Control Room Operator

R. Lane - Control Room Operator

R. Heilman - Control Room Operator

J. Fishell - Auxiliary Operator

R. Stotz - Auxiliary Operator

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• Personnel attending exit meeting.

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