ML20134L674

Insp Rept 50-289/85-20 on 850628-0802.Major Areas Inspected: Action in Response to Emergency Feedwater Sys Steam Binding at Other Facilities,Operability of TMI Task Action Plan Equipment Mods & Tube Plugging in Generators

ML20134L674
Person / Time
Site:	Three Mile Island
Issue date:	08/26/1985
From:	Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20134L645	List: ML20134L642 ML20134L674
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-1.A.1.2, TASK-1.A.1.3, TASK-1.C.3, TASK-1.C.6, TASK-2.B.3, TASK-2.D.3, TASK-2.E.1.1, TASK-2.E.4.2, TASK-2.F.2, TASK-2.G.1, TASK-TM 50-289-85-20, NUDOCS 8509030375
Download: ML20134L674 (30)

See also: IR 05000289/1985020

Text

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nc. 50-289/85-20

Docket No. 50-289

License No. DPR-50 Priority -- Category C

Licensee: GPU Nuclear Corporation

Post Office Box 480

Middletown, Pennsylvania 17057

Facility At: Three Mile Island Nuclear Station, Unit 1

Inspection At: Middletown, Pennsylvania

Inspection Conducted: June 28, 1985 - August 2, 1985

Inspectors: D. Haverkamp, Technical Assistant for TMI-1

Restart, Region I

R. Urban, Reactor Engineer, Region I

P. Wen, Reactor Engineer, Region I

F. Young, Resident Inspector (TMI-1), Region I

Approved By: M~ // b  % f/Jc /rs'

r p R. Conte, TMI I Restart Manager Date

TMI-1 Restart Staff

Division of Reactor Projects

Inspection Summary:

Routine safety inspection (180 hours0.00208 days <br />0.05 hours <br />2.97619e-4 weeks <br />6.849e-5 months <br />) of hot shutdown plant activities in

preparation for TMI-1 restart; licensee action in response to events occurring

at other reactor facilities including emergency feedwater (EFW) system steam

binding and mispositioned control rods; operability of TMI task action plan

equipment modifications; modification control program improvements including

updated status on EFW modifications; tube plugging in steam generators; pres-

surized thermal shock flux reduction program; licensee action on 10 CFR 21

reports; examination security; control room habitability ventilation system

test; licensee action on previous inspection findings; and overall restart

readiness.

8509030375 850827289

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Inspection Results:

Licensee upper management continued their detailed involvement in site activi-

ties. Personnel properly implemented facility procedures for hot shutdown

evaluations and testing. Licensee personnel took appropriate actions through

testing, procedural changes, and training in response to events at other

reactor facilities, i.e., steam binding in the emergency feedwater (EFW) system

and mispositioned control rods. The installed TMI Action Plan equipment was

operable although some discrepancies existed with Technical Specification

covering this equipment. The licensee continued to implement initiatives to

improve the modification control program. Reasonable progress continued on

modification work to upgrade the EFW system to full safety grade status. The

licensee design documents reflected restart hearing-imposed safety design

objectives. The licensee took appropriate action on issues addressed in an NRC

safety evaluation; various 10 CFR 21 reports, and previous inspection findings

including two violation responses. The plant remains physically ready for

restart, however, the reliability of one of two source range channels for

nuclear instrumentation needs to be evaluated as to its impact on a safe

restart of TMI-1.

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DETAILS

1.0 Introduction

At the beginning of this inspection period on June 28, 1985, the plant was

at normal hot shutdown conditions (about 530 F and 2150 psig) to complete

licensed operator familiarization training, pending further action by the

U.S. Court of Appeals for the Third Circuit in Philadelphia, Pennsylvania.

As discussed in NRC Region Inspection Report Number 50-289/85-19, the

Court of Appeals on June 7,1985, stayed the Commission Restart Order

(CLI-85-09). No further court action has been taken and the facility

remained at hot shutdown for the remainder of the inspection period.

Inspection coverage was provided by the resident inspector and support

staff components of the NRC TMI-1 Restart Staff.

2.0 Plant Operations During Hot Shutdown '

2.1 Routine Review

The resident inspectors periodically inspected the facility to deter-

mine the licensee's compliance with general operating requirements of

Section 6 of the Technical Specifications (TS) in the following

areas:

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review of selected plant parameters for abnormal trends;

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plant status from a maintenance / modification viewpoint including

plant housekeeping and fire protection measures;

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control of ongoing ard special evolutions, including control

room personnel awareness of these evolutions;

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control of documents including log-keeping practices;

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implementation of radiological controls; and,

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implementation of the security plan including access control,

boundary integrity and badging practices.

The inspectors focused on the following areas:

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control room operations during regular and backshift hours

including frequent observation of activities in progress and

periodic reviews of selected sections of the shift foreman's log

and control room operator's log and selected sections of other

control room daily logs;

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areas outside the control room; and,

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selected licensee planning meetings.

The inspectors identified no conditions adverse to nuclear safety or

inconsistent with regulatory requirements.

2.2 Summary of Findings

Overall, personnel stationed in the control room exhibited control of

daily activities, including problem areas that needed resolution.

Licensee planning meetings stressed attentiveness to proceed safely

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with daily activities, including surveillance and maintenance and to

resolve any inter-departmental interface problems. Licensee upper

management continued their detailed involvement in site activities.

3.0 Licensee Actions in Response to IE Information Notices

The inspector reviewed the licensee's action associated with IE Informa-

l tion Notice (IN) 84-06, " Steam Binding of Auxiliary Feedwater Pumps," and

l IN 83-75, "Mispositioned Control Rods." The inspector also reviewed the

corresponding Institute of Nuclear Power Operations (INPO) Significant

Operating Experience Reports (SOER).

3.1 Steam Binding in Emergency Feedwater System

l The inspector reviewed the licensee's current methodology on identi-

I fying steam back-leakage into the emergency feedwater (EFW) system.

! The inspector noted, at the beginning of the inspection period, that

l the licensee was training their auxiliary operators in a general

manner to determine if there were any abnormal plant conditions in

the intermediate building. It was not apparent how the specific

problem of back-leakage in the EFW system was addressed in training

sessions.

Licensee representatives initially indicated that if steam back-leakage

into the EFW system occurred, this would probably be noticed during

l the monthly surveillance check of the EFW pumps. Prior to this time,

! the licensee had performed a one-time test during the last hot

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functional test (HFT) in April 1985 to determine if such back-leakage

( occurred. Temperature readings at specific EFW piping locations were

! taken over an eight hour period. These test results indicated no

! back-leakage into the system. In addition, the licensee inspected

certain EFW valves prior to this HFT and they found no significant

, wear or wastage of valve internals.

After discussion of the problem with the inspector, the Plant Opera-

tions Manager initiated a procedure change request (PCR) that added a

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requirement to auxiliary operator shift logs to check for back-

leakage into the EFW system. In addition, he wrote a shift briefing

sheet to re-emphasize the safety concern about steam binding.

Operations personnel reviewed the shift briefing sheet.

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The inspector concluded that the licensee actions were adequate

measures to detect back-leakage into the EFW system if it occurred.

3.2 Mispositioned Control Rods

Based on discussions with the TMI-1 lead nuclear engineer, the

inspector reviewed the licensee's actions regarding rod misposi-

tioning and how they would recover from this type of problem. The

inspector discussed the rod misalignment event that occurred at ANO-1

to ensure that the lessons learned from that event were incorporated

into station procedures. The engineer demonstrated how their

procedures addressed this concern.

The licensee conducted specific simulator training that addressed

mispositioning of a control rod. A review of the lecture guides and

other training material showed that there were specific and defined

methods on how to recover a misaligned or dropped rod. The inspector

also reviewed the licensee's training plans used during simulator

training and, independently, reviewed applicable station procedures.

The inspector concluded that information presented was detailed

enough that an operator could develop a working knowledge of the core

physics aspects of a misaligned rod. Review of station proce-

dures indicated that necessary guidance was reflected in the appli-

cable procedures.

4.0 Operability of TMI Task Action Plan Equipment Modifications

The purpose of this review was to assess, on a sampling basis, the opera-

bility status of completed TMI Action Plan (TAP) required equipment and

procedural controls modifications specified in NUREG 0737. The review

consisted of evaluating the present status of installed plant equipment,

modifications, and any program / procedure requirements to determine if the

TAP requirement was met on a continuing basis. The TAP items reviewed

included I.A.l.2, I.C.3, I.C.6, I.A.l.3, II.B.3, II.D.3, II.F.2, II.E.1.1,

II.E.4.2 and'II.G.l.

As part of this review, the inspectors referred to NUREG 0660, "NRC

Action Plan De'veloped as a Result of the TMI-2 Accident;" NUREG 0737,

" Classification of TMI Action Plan Requirements," TMI Unit 1 Tech-

nical Specifications (TS); and the NRC resident office files related

to TAP correspondence.

The inspectors determined which TAP items were applicable and if any

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plant equipment, modifications, or TS changes were made as a result

of each TAP item. All TS associated with the TAP items were reviewed

for adequacy and completeness.

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The inspectors also walked down various systems throughout the plant

such as emergency feedwater equipment, controls and indication, and

inadequate core cooling instrumentation.

The inspectors identified no conditions adverse to nuclear safety or

inconsistent with regulatory requirements. The licensee completed

modifications and related technical specification (TS) changes (approved

by NRR) in accordance with NRC staff requirements and guidelines. The

inspectors identified certain existing TS that might be improved by

additional changes in wording and/or format; but, in all instances, the

inspectors considered the TS to be enforceable in assuring operability of

related equipment. Further, the TS, as approved, were consistent with

applicable NRC staff generic letter guidelines. The inspectors'

suggested TS improvements will be reviewed by Region I for generic

applicability and forwarded to NRR, if applicable.

5.0 Modification Control Program - Selected Aspects

At the corporate office (Parsippany, New Jersey), the resident inspector

reviewed selected aspects of the modification control program. He also

obtained a statui on the upgrade modifications for the emergency feedwater

system.

5.1 Modification Task Force Improvements

The licensee responded to the latest NRC Systematic Assessmen; of

Licensee Performance (SALP) (NRC Inspection Report 50-289/85-99) by

letter dated May 7,1985, from H. Hukill, Director, TMI-1, to

T. Murley, Region I Regional Administrator, and specifically

addressed improvements in the Design, Engineering, and Modification

functional area. They reported that the Office of the President

approved the GPUN Modification Task Force (Task Force) recommenda-

tions discussed in the SALP. During this inspection period, the

inspector discussed the status of the Task Force recommendations with

the GPUNC Director of Engineering, Director of Licensing, and Manager,

TMI-1 Long Range Planning.

The inspector learned that a documented update to these recommenda-

tion was to be prepared and he determined that reasonable progress is

being made to resolve the concerns embodied in the Task Force report.

Of particular interest to the inspector were actions related to the

Task Force observation that too much work (beyond resource capability)

was planned for a given outage period.

The inspector determined that licensee management took direct steps

for better outage planning. They created two new planning positions

that now report to the Vice President of Technical Functions (for

Oyster Creek and TMI-1). Modification items were placed on a

computerized list which was to identify the regulatory source organi-

zation (such as NRR, IE), the particular outage and cycle during

which they planned to implement the item, responsible engineer, and

estimates of ALARA exposure in addition to staff-hour estimates for

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engineering and construction. The computerized list for TMI-1 was to

receive inputs from various GPUNC divisions for complete planning

information and assurance that regulatory and corporate schedule ob-

jectives were met. Overall, the inspector concluded that these posi-

tive licensee initiatives, if properly and fully implemented, could

serve to enhance reactor safety. These measures would assure a

methodical outage implementation with the avoidance of last minute

engineering changes for safety-related system modifications.

Further, during the above discussions, the inspector determined that

licensee management planned to issue a consistent set of engineering

specifications, installation standards, and inspection standards to

assure an up-front and consistent engii. ering implementation, and

verification of regulatory requirements and industrial standards for

all modifications including those affecting safety systems. This is

a long-term improvement item.

5.2 Preliminary Engineering Design Review

The inspector reviewed Technical Functions Procedure 5000-ADM-7311.03

(EMP-014), Revision 1-00, effective April 12, 1985, " Project Reviews"

as it related to the conduct of Preliminary Engineering Design

Reviews (PEDR) meetings. At the site, on July 18, 1985, the inspec-

tor monitored a PEDR (second meeting for operations department repre-

sentatives) on modifications for 10 CFR 50, Appendix R. Also, at the

corporate office on July 24, 1985, the inspector monitored a PEDR

(the last in the series of several PEDRs) on modifications to install

an engineered safety features ventilation system for the fuel handling

building.

On a sampling basis, the inspector verified proper implementation of

EMP-014 with respect to PEDR requirements. Licensee attendees pro-

vided their expertise and experience to pose thoughtful and challeng-

ing questions to the design engineers. Various company disciplines

were represented including site plant engineering, site radiological

engineering, site maintenance and construction planning, in addition

to corporate engineering and quality assurance representatives. The

PEDR chairman controlled the meeting and ensured that safety concerns,

regulatory requirements, industrial standards, and practical site-

specific concerns were adequately addressed in licensee design docu-

ments (primarily system design descriptions and safety evaluations).

Overall,'the meetings showed continued implementation of this

resource-intensive licensee initiative and appeared to be focused

toward producing quality products that directly enhance plant safety.

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5.3 Emergency Feedwater System Upgrade

5.3.1 Introduction

As a result of the TMI-2 accident, the NRC ordered TMI-1 shut

down because it did not have "...the requisite reasonable as-

surance that the same licensee's Three Mile Island Unit I can

be operated without endangering the health and safety of the

public" (Commission Order, dated July 2,1979). In a Commission

Order, dated August 9, 1979, the Commission specified that the

following licensee actions must be taken with respect to the

emergency feedwater (EFW) system:

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upgrade the timeliness and reliability of the EFW-in accor-

dance with licensee proposed actions, in letter dated June

28, 1979;

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develop _and implement operating procedures for initiating

and controlling EFW independent of integrated control

system (ICS);

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complete analysis of potential small breaks, and develop

and implement instructions to define operator actions; and,

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provide reasonable assurance of the safety of long term

operation with outstanding category B items of NUREG 0578

(later became Task Action Plan Items II.E.1 and II.E.1.2 of '

NUREG 0737). ,

The short term licensee actions were verified as a part of the

staff's restart certification process to the Commission (SECY

85-192, May 29, 1985). Additional licensee actions taken were

as a result of Union of Concerned Scientist (UCS) 2.206 Petition

in early 1984. The NRC staff reviewed and verified these actions

as noted in NRR Director Decisions 84-12, dated April 27, 1984,

and 84-22, dated September 25, 1984; and NRC Inspection Reports

50-289/84-21, 84-22, and 84-38. The long-term licensee actions

with respect to upgrading the EFW system to full safety grade

status are summarized in paragraph 5.3.3.

5.3.2 Scope of Review

The purpose of this review was to update the status of EFW long-

term modifications and verify that the licensee incorporated

NRC-imposed design objectives into licensee design packages /

documents for subsequent plant installation. The inspector

reviewed applicable licensing and appeal board decisions and

related staff safety evaluations to identify the outstanding

long term items. He also reviewed applicable licensee letters

and licensee internal design documents.

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5.3.3 Detailed Status

Listed below are the applicable design documents for various EFW

upgrade modifications /or licensee evaluation along with status

of construction and testing.

5.3.3.1 Mechanical System Modifications

5.3.3.1.1 Add cavitating venturis (and vibration supports) in

EFW discharge piping (289/83-BC-16)

References

(1) Atomic Safety and Licensing Board (ASLB)

Partial Initial Decision (PID),on the Restart

Hearing, dated 12/14/81, paragraph 1037, item

No. 1

(2) NUREG 0680, NRC Staff TMI-1 Restart Safety

Evaluation Report and Supplement 3, Order Item

8-2.1.7.(a), Item No. 1

(3) System Design Description (SDD)-1-424B,

Division (Div) 1, Revision (Rev.) 4, Item

1.1.1

(4) Licensee Letter (LL) (5211-85-2057), dated

April 19, 1985, from H. Hukill, TMI-1, to

J. Stolz, NRC, Enclosure (Encl.) 1, Item 1.3.1

This was completed for restart and verified in NRC

Inspection Reports 50-289/82-26, 83-01, 83-12, 83-14,

and 84-01. This was considered by the staff to be a

long-term modification but it was relied upon by the

staff to limit EFW flow to an affected once through

steam generator (OTSG) on main steam /feedwater line

rupture to resolve an ASLB concern. The concern was

that inadvertent actuation of the then non-safety grade

portion of the steam line rupture detection system would

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isolate EFW. The isolation function was removed by the

licensee and it was verified in NRC Inspection Report

50-289/83-01, thereby resolving this concern.

5.3.3.1.2 Provide redundant safety grade EFW control and

block valves (289/83-BC-01 and 03) ,

References

(1) sASLB PID, dated 12/14/81, paragraph 1036

(2) NUREG 0680, and Supplement 3, Order Item

8-2.1.7.a(2)

(3) SDD-424B, Revision 4, Item 1.1.2

(4) LL of April 19, 1985, Enclosure 1, Item 1.3.2

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The mechanical portion of this modification is

complete. Electrical work is controlled by the

installation of the heat sink protection panel,

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the status of which is addressed in paragraph

5.3.3.5 of this report.

5.3.3.2 Structural Modifications

References

l (1) SDD-4248, Div. 1, Rev. 4, Items 1.2.1, .2, .3

(2) LL of April 29, 1985, Encl. 1, Items 1.3.3,

.4, and .5

(3) LL of February 13, 1985, from B, Hukill,

GPUNC, to J. Stolz, NRC, Correction to NRC

Inspection Report 50-289/84-37

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These modifications were: upgrade of EFW pumps recirculation

lines to Seismic Category I (as described in reference (3)); up-

grade vent stacks for safety valve and atmospheric dumps to

Seismic Category I; and provide increased flood protection in the

intermediate building for a main feedwater line break. These modi-

fications were completed and were verified by NRC Region I in

response to the USC 2.206 Petition of 1984 and subsequent NRR

Director Decisions.

5.3.3.3 Electrical Modifications

5.3.3.3.1 Provide a safety grade power supply to valves

C0-V111 A/B and upgrade cable routing for power

supply to valve CO-V V14 A/B

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Reference

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(1) LL 83-232, dated August 23, 1983, in response

to TAP II.E.1.1 (Section IV.B.1, page 5)

(2) SDD-4248, Div. 1, Rev. 4, Item 1.3.1

(3) LL of April 29, 1985, Encl. 1, Item 1.3.6

These valves have the safety function of isolating a damaged

condensate storage tank (CST) (C0-Villa /B) or isolating non-

safety systems from the EFW system (C0-V14A/B). This work is

related to the extensive cable and conduit work required

for meeting safety grade criteria and meeting 10 CFR 50,

Appendix R. The status of the cable and conduit effort is

addressed in paragraph 5.3.3.5 of this report.

5.3.3.3.2 Delete cross connect between electrical busses that

allows an operator to load both EFW electric driven

pumps on a single diesel generator

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References-

(1) LL 83-232, dated August 23, 1983, in response

to TAP II.E.1.1 (Section IV.B.2, page 16)

(2) SDD-4248, Div. 1, Rev. 4, Item 1.3.8

- (3) LL of April 29, 1985, Encl. 1,' Item 1.3.18

Reference 1 reported this item complete from a human factors

viewpoint, that is, operator error causing a diesel generator

overload. In a later design document (reference (2)) the-

licensee relied on this modification to fulfill electrical

separation criteria for redundant electrical systems. The

licensee completed this modification prior to the restart hear-

ing in 1980 by Engineering Change Memorandum S-225. The

inspector reviewed licensee records on this modification and he

examined control room panels for the control of EFW electric-

driven pumps. The inspector concluded that the licensee

properly deleted the subject power cross-connect function from

EFW pump control.

5.3.3.3.3 Review of diesel generator bus loadings to assure

no overload situation exists as a result of system

modifications

References

(1) LL 83-232, dated August 23, 1983, in response

to TAP II.E.1.1 (Section IV.B.3, page 6)

(2) LL 84-2304, dated January 11, 1984, on

computer program for diesel generator bus

loadings

As committed to in reference (1), reference (2) documented the

satisfactory results of the licensee's computer analysis of

diesel generator bus loadings as a result of modifications made

to the facility. The licensee concluded that no overload situ-

ation would exist.

These documents will be reviewed by NRR as a part of TAP

II.E.1.1 and .2 reviews.

5.3.3.4 Instrument and Control Modifications

! 5.3.3.4.1 Deletion of the main steam line rupture detection i

system (MSLRDS) signal to emergency feedwater '

control valves (289/83-BC-10)

l References

(1) ASLB PID, dated 12/14/81, paragraph 1064

[L (2) ALAB 729, dated 5/26/83, pages 35 and 176

I (3) LL 82-153, dated August 2, 1982

i (4) NRC letters (NRR), dated November 10, 1982 and

( August 30, 1983

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(5) Commission Memorandum and Order CLI 84-11,

dated July 26, 1984

(6) NRC Inspection Report 50-289/83-01

(7) SDD-423B, Div. 1, Rev. 4, Item 1.3.2

(8) LL of April 29, 1985, Encl. 1, Item 1.3.17

In reference (1), the ASLB raised the concern of the non-safety

grade MSLRDS inadvertently isolating EFW. In reference (2) the

ALAB noted that the licensee's proposed resolution (deletion of

the MSLRDS signal to EF-V 30A/B) should be reviewed by the

Commission after NRC staff review. Reference (3) documented

the licensee's proposed resolution. In reference (4) NRC staff

accepted the licensee's proposed resolution and forwarded their

review to the Commission. In reference (5) the Commission also

accepted the licensee's resolution of the ASLB concern. The NRC

staff verified completion of licensee action as documented in

reference (6). References (7) and (8) incorporated the design

objectives into licensee design documents.

5.3.3.4.2 Provide safety-grade automatic initiation and

control of EFW (289/83-BC-01 and 06)

References

{1) ASLB PID, dated 12/14/81, paragraph 1036

(2) SDD-4238, Div. 1, Rev. 4, Items 1.3.3, 1.3.4

and 1.3.5

(3) LL of April 29, 1985, Enc 1. 1, Items 1.3.9,

1.3.11,.1.3.14, and 1.3.16

The EFW auto initiation restart modifications were to be

retained and these modifications included auto initiation of EFW

on loss of both main feedwater pumps or on loss of all four

reactor coolant pumps. Planned modifications were automatic

initiation of EWF on high containment pressure and low steam

generator water level.

The controlling work in these planned modifications is the

installation of the heat sink protection system panels which

contain the logic actuation sub-systems for EFW initiation.

Licensee design requirements include safety grade criteria for

the initiation system. The status of the HSPS installation is

addressed in paragraph 5.3.3.5 of this report.

The control functions will remain similar to that committed to

in the restart hearing, that is, EF-V 30A/B actuation to main-

tain level in the OTSG startup range with reactor coolant pumps

on or in the operating range (higher level) on loss of reactor

coolant pumps to assure natural circulation. The safety grade

j redundant block and control valves for each OTSG will be

controlled by the HSPS logic system.

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5.3.3.4.3 Provide safety grade OTSG level instrumentation

with signal to initiate EFW and isolate MFW on high

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water level in the OTSG (289/83-BC-08 and 18) ,

References s

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(1) ASLB PID, dated 12/14/81, paragraph 1037, Item

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(2) NUREG 0680 and Supplement 3, Order Item

8-2.1.7.a(3)

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(3) SDD-4248, Div. 1, Rev. 4, Item 13.4

(4) LL of April 29, 1985, Encl. 1, Item 1.3.10

Instrument transmitters are installed and the remaining work is

being accomplished with HSPS installation.

Licensee design documents (references (3) and (4)) reflect

design objectives as noted in references (1) and (2).

5.3.3.4.4 Upgrade MSLRDS to safety grade to assure isolation

of MFW and prevent a potential overpressurization

of containment on steam line break in containment

(289/83-BC-09)

References

(1) ASLB PID, dated 12/14/81, paragraph 1037, Item

i No. 5

(2) ALAB, 7-29, dated 5/26/83, page 36

(3) SDD-4248, Div. 1, Rev. 4, Item 1.3.6

(4) LL of April 29, 1985, Encl. 1, Item 1.3.12

Safety grade logic actuation is provided by HSPS panels. The

HSPS and related cable and conduit installation is addressed in

paragraph 5.3.3.5. The design objectives, as noted in refer-

ences (1) and (2), are incorporated into licensee design docu-

ments, references (3) and (4).

5.3.3.4.5 Provide safety grade condensate storage tank level

installation and low water level alarm

(289/83-BC-07 and 19)

References

(1) ASLB PID, dated 8/14/81, paragraph 1037, Item

No. 2

(2) NUREG 0680 and Supplement 3, Order Item

8-2.1.7.a, Item No. 5

, (3) SDD-4248, Div. 1, Rev. 4, Item No. 1.3.7

(4) LL of April 29, 1985, Encl. 1, Item No. 1.3.13 ,

. , -. =-.

. . - .. -- . _ _. __

...

.

.

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13

This work is part of the cable and conduit effort. The design

objectives of references (1) and (2) are incorporated into the

licensee's design documents (references (3) and (4)).

5.3.3.4.6 Provide safety grade OTSG high level alarm

(289/83-BC-13)

References

(1) ASLB PID, dated 8/14/81, paragraph 1037, Item

No. 3

(2) NUREG 0680 and Supplement 3, Order Item No.

8-2.7.1.a, Item No. 7

(3) SDD-424B, Div. 1, Rev. 4, Item No. 1.3.4

(4) LL of April 29, 1985, Encl. 1, Item No. 1.3.10

The design objectives were incorporated into the design of new

OTSG water level instrumentation as noted in paragraph 5.3.3.4.3

above.

5.3.3.4.7 Other licensee proposed modifications / actions

References

(1) SDD-424B, Div. 1, Rev. 4, Items-1.3.9.10,

1.5.3

(2) LL of April 29, 1985, Encl. 1, Items, 1.3.7,

.8, .20

The following additional modifications were proposed and are

being implemented by the licensee:

--

overspeed trip alarm for the turbine-driven EFW pumps;

I , --

safety grade pit level (flood detection) alarm for inter-

mediate building and control grade condenser hotwell low

l level alarm; and,

--

evaluate performance of electric and instrument control

!

'

cables in the event of flooding in the intermediate

building.

These proposals are under review by the NRC staff in conjunction

with SER development for TAP II.E.1.2, Auto Initiation of EFW.

o

,

5.3.3.5 Summary and Conclusion

,

The controlling work effort is cable and conduit installation

~

along with HSPS cabinet installation and wire termination. This

work involves extensive resources and is delayed, in part, for

.

'

procurement and receipt of qualified material. Extensive

preoperational and startup testing is planned. If TMI-1

restarts, then system tie-ins and testing will be delayed.

_ , _ _ _ _ _ _ ___ _ _ __ _ _ . . _ _ __ __ __ . _ . _ _ _ _ .

.

.

14

However, the cycle 6 startup (first refueling after restart)

commitment to the NRC should be met.

Based on the above review, the inspector concluded that NRC-

imposed safety design objectives, as a result of the restart

hearing, were properly incorporated into licensee design docu-

ments.

The proper implementation of the safety grade design require-

ments is unresolved pending completion of licensee action and

subsequent NRC Region I review (289/85-20-01).

~

6.0 Operation of TMI-1 with 2,000 Plugged Steam Generator Tubes

In NUREG 1019, the NRC staff evaluated the licensee's analyses on the

effects of operating TMI-1 once through steam generators (CTSG) with 1,500

tubes plugged. The staff found that transient and accident consequences

resulting from operation with 1,500 tubes plugged were bounded by the FSAR

analyses, and therefore subsequent operation was acceptable.

To date, a total of 1,542 OTSG tubes have been plugged. To support this

additional plugging, the licensee provided to the NRC resident irspector,

TDR No. 674, Revision 1, " Comparison of Steam Generator Tube Plugging with

the TMI-1 Design Basis." This document stated that plugging up to 2,000

tubes will not adversely affect plant operation and is still bounded by

the FSAR. The licensee plans to officially submit TDR No. 674 (current

revision) to the NRC.

At the request of NRC Region I, the NRC Office of Nuclear Reactor

Regulation (NRR) reviewed and evaluated the licensee's analysis. The NRR

staff's safety evaluation (SE), attached to this report, confirmed that

operation with up to 2,000 plugged tubes does not involve an unreviewed i

safety question and the conclusions in NUREG 1019 remain valid for up to

2,000 tubes. In addition, the SE stated that the upper number of 2,000

tubes was acceptable as long as the plugging ratio between OTSGs does not

exceed a 3 to 1 ratio.

The inspector discussed the SE with appropriate licensee representatives.

The inspector stated that if the licensee, at a later date, was required

to plug in excess of 2,000 tubes or exceed the 3 to 1 plugging ratio, an

additional evaluation would be required to be performed per 10 CFR 50.59

in order to return the unit to operation. No further licensee action

regarding this matter is required at this time.

7.0 Pressurized Thermal Shock Flux Reduction Program

A concern on the capability of pressurized water reactor pressure vessels

to withstand a severe pressurized thermal shock (PTS) without compromising

reactor vessel integrity was under intensive examination by the NRC. A

neutron flux reduction program was proposed by the licensee to reduce

neutron-induced radiation embrittlement of the reactor vessel. The NRC

reviewed the licensee's flux reduction program and concluded in its safety

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

.

. .

15

evaluation that the licensee adequately addressed this issue (NRC letter

dated March 14, 1985, from J. F. Stolz, NRC to H. D. Hukill, GPUNC). The

NRC's conclusion was based on the licensee's plan to implement a low-

leakage fuel loading scheme in future cycles of operation.

~

Based on discussions with the site lead nuclear engineer and later

confirmed by a GPU Headquarters nuclear fuel engineer (through telephone

conversation), the inspector noted that the low-leakage fuel loading scheme

(in-out-in strategy) is planned for Cycle 6 reload. However, due to the

long delay in Cycle 5 restart, the actual Cycle 6 fuel design was not

initiated. The proper design and implementation of the flux reduction

scheme for Cycle 6 reload is unresolved pending completion of licensee

action and subsequent NRC Region I review (289/85-20-02).

8.0 Part 21 Report Followup

The inspector reviewed the below noted 10 CFR 21 and 10 CFR 50.55(e)

Reports to ascertain the nature of the problems (deficiencies) as related

to TMI-1. Subsequently, he reviewed licensee corrective actions to ascer-

tain if the licensee received complete and appropriate information from

the applicable vendor and if licensee corrective actions were adequate to

resolve the deficiency consistent with vendor recommendations.

8.1 Small Break Operating Guidelines (SB0G)

Reference

B&W letter from J. H. Taylor to R. C. DeYoung, dated

July 29, 1983 (Part 21 Report)

The original SB0G did not deal to any great extent with the

pressurized thermal shock issue. As a result, it is possible to have

misused or misinterpreted a statement contained in the SB0G. The

reference letter clarified the ambiguities, specifically the repres-

surization restriction following the RCS cooldown below 500 F not to

exceed a rate greater than 100 F/hr. The inspector reviewed the

Abnormal Transient Procedure 1210-10, Figure 1, and noted that the

PTS concerns and proper RCS cooldown rates were clearly included in

the procedure. The inspector had no further questions.

8.2 HPI Throttle Valves

References

(1) Letter from G. R. Westafer (Florida Power Corpora-

tion) to J. P. O'Reilly (NRC Region II), dated June

27, 1983 (Part 21 Report)

(2) IE Information Notice No. 80-48 and Supplement 1

The failure of throttling HPI valves and similar failures involving

Rockwell International globe valves were reported to the NRC. The

licensee uses 2 1/2" Rockwell International globe valves in the HPI

_

. .

.

16

lines at TMI-1 for throttling purposes (MU-V 16 A through D). The

,

inspector discussed this subject with the licensee mechanical engine-

ering representative and he learned that the licensee was aware of

the problem encountered at the other sites. This is evidenced in the

completion of the licensee's Licensing Action Item No. 84-9519.

As a result of the licensee's evaluation, a procedure note cautions

against backseating valves with torque switches set in accordance

with Corrective Maintenance Procedure 1420-LTQ-1, "Limitorque Opera-

tor, Limit Switch Adjustment," Revision 8. The inspector further

reviewed the machinery history report for MU-V 16A through D, and found

no similar deficiencies were ever recorded in the plant history. The

inspector also reviewed the hign pressure injection flow test results

(SP 1303-11.8) performed on April 11-12, 1985, and noted that no un-

acceptable conditions were identified. The inspector concluded that

the licensee either had or had taken reesonable measures to assure

operability of the HPI throttling valves.

8.3 D.C. Batteries

Reference

Letter from W. P. Murphy (Vermont Yankee Nuclear Power

l Corporation) to T. E. Murley (NRC, Region 1), dated June

29, 1984 (Part 21 Report)

.

A potential deficiency involving corrosion in the lead posts of the

I batteries supplied by Exide Corporation was reported for Vermont

( Yankee. Through discussions with the licensee's cognizant representa-

tive, the inspector learned that the station batteries were supplied

! by C&D Corporation. Appropriate preventive maintenance has been

implemented to ensure the operability of the station batteries. The

inspector physically walked down the 'A' and 'B' battery rooms and

,_ noted that battery posts were clean with no crud buildup, and no

i

cracking or negative plate discoloration. The licensee had previously

noted cell cracking at TMI-1 but reasonable measures are in place to

j assure the timely detection of cracks before they would affect the

i operability of the battery bank. Battery bank replacements are

,

planned for a future refueling outage.

8.4 Hydrogen Recombiner

8.4.1 References

(1) Letter from D. C. Empey (Rockwell

International) to U. Potapovs

(NRC, Vendor Inspection Brarch), dated

December 15, 1981

(2) Letter from D. C. Empey to J. Collins

(NRC, Region IV), dated May 5, 1983 (Part

21 Report)

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(Part 2h Report)

s (4) Letter f rom D. C. Empey.19, 1983 ,to J. Collins,

dated December '

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,'(5) IE Information Notice No. 85-08, Item 3 ,

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(6) IE Information Notice No. 83-72, Items >17 & 18 '

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8.4.'2 A . Review / Findings

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As a result of environmental qualification testing exper-

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ifence, sdveral concerns related to the hydrogen recombiner.' '

coOpon'ents were reported by'Rockwell International

'(Energy Systems Group). The following d'escribes each -

concern and the licensee's' response / action: - '

8.4.2.1 Viton Seals '

s

'

d ton seals were used at the recombiner inlet and outlet

piph-to-blower housing flanges, and at the blower flowmeter'.  :

The material's sealing capability may be degraded due to

exposure to radiation, levated temperature, and steam

envi ronments'.- The licensee has evaluated this problem

(Pemorandum'frem S. U. Zaman to D. Shovlin/R. Knight," dated

May 24, 1985). .As"a result, new qualified seals have,been

s ordered and the replacement s has been scheduied on an annual

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8.4.2.2 LeadwireInshl'atinn  !

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The o\righ al h ater'leadwire' routing areas may reach

temperatures higher than the leadwire insulation design

l rating (194 F). 'fluring the iccidqnt conditions, this may .

result in a reduced service for t.he leadwire insulation.

The licensee corrected this probler by installing a new g

qualified leadwire per job ticket No. CA075 on January. 24,

1983.

'

. ,

8.4.2.3 Time Delay Rilay and Circuit Breaker

'

-

The subject components failed the vendor's environmental

'

.

qualification, test. However, these components at TMI-1 are

-Icceted Jithin"the intermediatetbuilding and are not

exsosehto a' postulated LOCA coddition. The test results

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8.5 Conclusion

The licensee has taken proper corrective action in response to

the various 10 CFR 21 Reports, IE Information Notices, and

Industrial Experience Reports noted above.

9.0 Security of TMI-1 Operator Examinations

Additional review of the subject matter was conducted as a result of Three

Mile Island Alert's (TMIA) appeal to the Atomic Safety and Licensing

Appeal Board subsequent to the issuance of NRC Inspection 50-289/85-12.

The incident involved the discovery of a microfiche copy of a TMI-1

auxiliary operator examination in the TMI-2 parking lot. Subsequent

investigation determined it to be a record of a completed examina-

tion that had been administered about a year prior to its discovery.

In accordance with the licensee's procedures, examination security

requirements for Category 1 examination materials applies to the

period of time when an exaniination is prepared, administered and

graded. Once this process is completed, the materials become a

record and are not considered to be Category I materials.

Based on discussions with licensee personnel and a review of applicable

procedures, the inspector determined that completed examinations are

i controlled until the administration of examinations to all operators is

completed. Copies of the examinations are subsequently decontrolled and

made available to the operators if requested.

Previously administered examinations are produced from an examination

question bank and the requirements for the selection of questions from the

bank are such that the contents of a new examination are not identical to

any previous examination. This assures that the potential for any par-

ticular examination containing a substantial number of the same questions

as a previous examination is extremely remote. Nothing would preclude an

operator, once in receipt of a graded examination, from generally

distributing it. A parallel of this process is the program for NRC-

administered licensed operator examinations in that, although exams to be -

administered are secured, once they have been administered and graded

they, along with the answer key, become a public record.

In summary, the licensee met its procedural requirements for the

control of examinations and thereby continued to implement the com-

mitments made to the licensing board.

10.0 Control Room Habitability Test

During this inspection period, the resident inspector accompanied an NRR

systems engineer in witnessing portions of Startup and Test Procedure

(STP) 141/3, " Control Building (dP) Test with Single Mode Failure." The

inspector found the STP to be detailed and specific enough to ensure that

the tes; met the scope or stated objective of the test. The test results

__ ___

.

.

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indicated areas within the control building that were at a lower pressure

than adjacent areas. The NRR systems engineer discussed the test results

, with the licensee's representatives and stated that their submittal to the

! NRC would have to demonstrate that these low pressure areas would not have

!

an adverse affect on the habitability of the control room. The inspector

had no further questions regarding this test.

11.0 Licensee Action on Previous Inspection Findings

'The following items were reviewed to assure that the licensee took ade-

quate corrective action in a timely manner and/or met their commitments as

stated in applicable inspection reports.

11.1 (CLOSED) Inspector Follow Item (289/83-BC-02): Instal-

lation of Engineering Safety Features (ESF) Ventilation

System for the Fuel Handling Building (FHB)

The NRC staff TMI-1 Restart Safety Evaluation Report (NUREG 0680,

Supplemant 3, page 19) accepted licensee plans to install the ESF

Ventilation System for the FHB in accordance with Regulatory Guide

1.52, Revision 2. By Partial Initial Decision, dated December 14,

1981, paragraph 1265 and Order, dated April 5, 1982, the TMI-1

-Restart ASLB accepted these plans for a commitment of prior to TMI-I

fuel movement from the reactor core for Cycle 6 refueling.

The inspector monitored a licensee preliminary engineering design

review at the corporate office (paragraph 5.2). The inspector

verified that the safety design objectives as a result of the TMI-1

restart hearings were incorporated into licensee design documents

specifically or by reference to Regulatory Guide 1.52, Revision 2.

Inspector Follow Item 289/83-BC-02 is considered closed. However,

proper implementation of the design requirements is unresolved

pending completion of licensee action and subsequent NRC Region I

review (289/85-20-03).

11.2 (CLOSED) Inspector Follow Item (289/83-BC-01, 03, 06, '

07, 08, 09, 13, 18, and 19): Various modification

commitments to upgrade the emergency feedwater system to

safety grade

Additional details for each of the items is addressed in paragraph

5.3.3. The inspector verified that the safety design objectives are

incorporated into licensee design documents. The proper implementa-

tion of these design requirements to meet safety grade criteria is

unresolved (paragraph 5.3.3.5) pending completion of licensee actions

i

and subsequent NRC Region I review.

l

. . _ _ _ _- _ J

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20

11.3 (CLOSED) Inspector Follow Item (289/84-11-02): Update

RM-L6 Alarm Response Procedure

In NRC Inspection Report 50-289/84-11, the inspector noted that the

alarm response procedure (C-2-1 alarm procedure) for the plant liquid

release radiation monitor, RM-L6, lacked specific guidance on how

many times the monitor could be backflushed if the monitor alarmed.

The procedure did not address when sampling was required in conjunc-

tion with backflushing. The inspector noted that the alarm response

procedure was inconsistent with the licensee's approach to other

radiation monitoring alarms. Because the RM-L6 alarm signal is used

to terminate a plant release when the monitor exceeds a certain

radiation level, the inspector questioned the adequacy of management

guidance to shift personnel.

Subsequently, the licensee revised the C-2-1 alarm procedure. The

revised procedure stated that the monitor may be backflushed once

before a sample must be taken and analyzed. If the monitor did trip

after the backflush, the operator was to investigate the cause before

re-establishing the release. Based on the inspector's review, the

revised procedure is now consistent with the intent of the applicable

corresponding emergency and radiological control procedures.

11.4 (CLOSED) Violation (289/84-16-04): Failure to Properly

Follow Radiation Work Permit (RWP)

As described in NRC Inspection Report 50-289/84-16, the inspector, I

while witnessing the demonstration of post-accident chemistry analysis,

noted on two occassions the failure on the part of a chemistry

technician to wear an alarming dosimeter when entering the Nuclear

Sample Room. The applicable RWP required that a "Xetex" alarming

dosimeter.be worn by each individual. The licensee held a critique

to determine the cause of the violation. The licensee's review noted

that the chemistry technicians indicated that they were unaware that

the Xetex had to be worn by at least one person in the laboratory or

sample room when occupied. The technicians indicated that leaving

the dosimeter on a laboratory bench gave no less representative

exposure reading for technicians not assigned a Xetex than if the

dosimeter was being carried by a single technician in the group. The

licensee concluded the cause of the incident was the failure of

health physics personnel to properly communicate Xetex use require- ,

'

ments to the chemistry technicians.

GPU responded to this notice of violation in a letter (5211-84-2223),

dated August 30, 1984, to NRC Region I. The licensee stated that

corrective actions taken were:

--

a critique was held on the day of the incident. Radiological

Investigative Report No.84-009 details the actions and con-

clusions of this critique;

.

.

21

--

a memorandum detailing the requirements for use of a Xetex

instrument has been reissued to all TMI-1 departments; and,

--

all chemistry technicians have been instructed or otherwise

informed as to the requirements for use of the Xetex dosimeter.

The inspector reviewed the applicable licensee records that docu-

mented the above corrective action. The inspector also discussed the

corrective action with a plant chemistry foreman to ensure that the

use of alarming dosimeters was understood and discussed the cause

and corrective measures with station health physics personnel.

During this review the inspector noted that part of the root cause

also stemmed from a lack of familiarity by certain personnel on their

individual responsibilities associated with personnel radiation

, protection and as low as reasonably achievable (ALARA) concepts. The

inspector stated that these facts should be emphasized in the general

employee radiation training. However, the inspector noted that this

training was strongly emphasizing that if you had a " Rad Con" problem,

station health physics personnel were there to solve the problem.

Apparently, some general employees had translated this idea into the

belief that the Radiological Controls (Rad Con) Department was

responsible for assuring their protection in the area of radiation

exposure.

The Rad Con Manager restated that it was both the individuals' and

station health physics personnel responsibility. The licensee's

training representative stated they would review the training to

ensure proper emphasis on individual responsibilities. The Rad Con

Manager also stated that he was meeting with operation and mainte-

nance personnel to reemphasize items such as this. The inspector

determined that the licensee's corrective and preventive measures

were appropriate for this violation, and that individual misunder-

standings did not result in a radiological controls programmatic

breakdown.

4

11.5 (CLOSED) Unresolved Item (289/84-24-01): Licensee to

review job ticket for short form release to maintenance

for its completion

NRC Inspection Report 50-289/84-24 described an inconsistency on

how shift foremen were signing off the release of equipment to main-

tenance. This occurred when work was being performed on important to

safety equipment. Maintenance procedure 1407-1 did not provide

proper guidance on when shift foremen signatures are required to

commence work.

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

.

.

22

The inspector reviewed Maintenance Procedure 1407-1, Revision 23,

dated January 31, 1985. The inspector determined that adequate

guidance was now incorporated in this procedure. The inspector

reviewed package C-964, " Minor Maintenance on Various Components in

the Reactor Building," dated February 8,1985, and determined that

various job tickets were now being completed consistently.

11.6 (CLOSED) Violation (289/84-24-02): Failure to determine

the adequacy of minor maintenance work form to meet ANSI

18.7-1976

NRC Inspection Report 50-289/84-24 indicated that Maintenance Proce-

dure 1407-1, " Unit 1 General Corrective Maintenance," Revision 16,

dated August 23, 1984, was not reviewed, in part, for adequacy.

Specifically, for minor maintenance, the work form was not adequate

in that it did not provide for: 1) documented release of important

to safety system equipment to maintenance by the operations depart-

ment, 2) traceability of materials / parts, 3) documented use of

maintenance procedures, and 4) specified post-maintenance test

procedures including test acceptance criteria.

In a letter, dated December 5, 1984 (H. Hukill, GPUN to T. Murley,

NRC) the licensee responded to the above Appendix A, Notice of

Violation. Region I Inspection Report 50-289/84-38, described the

licensee's response to this violatien. The licensee's corrective

actions were acceptable as stated in an NRC Region I letter dated

March 13, 1985. However, the licensee was requested to provide a

supplemental response to more fully address the root cause and

corrective actions taken or planned to avoid further violations of

this type. A letter, dated April 12, 1985, (H. Hukill, GPUN to T.

Murley, NRC) provided the licensee's supplemental response.

The inspector reviewed Maintenance Procedure 1407-1, Revision 23,

dated January 31, 1985. The four items identified in the notice of

violation were adequately addressed in Revision 23; therefore, the

corrective steps taken by the licensee were acceptable. The correc-

tive actions to prevent further violations of this type was to pro-

vide guidance to all safety reviewers in the TMI-1 division. This

was accomplished by an internal licensee memorandum dated April 9,

1985, (Nelson, GPUN, to PORC Members, 3200-85-9016). The inspector

determined that this memorandum was a reasonable measure to pre-

vent similar violations in the future. The effectiveness of these

measures will be routinely reviewed by the resident inspectors.

11.7 (CLOSED) Inspector Follow Item (289/84-37-01):

Inservice Testing (IST) Program Stroke Timing Requirements

NRC Region I Inspection Report 50-289/84-37 indicated that the river

water supply to emergency feedwater system suction check valve EF-V3

l was only partially stroke tested in the in-service testing (IST) program.

Also, stroke timing for turbine driven EFW pump steam supply line valves

l MSV-10A and MSV-108 was not included in the surveillance procedure.

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.

23

By various letters to the NRC the licensee sought IST relief for

EF-V3 to conduct partial stroke testing in lieu of full stroke

testing as required by the ASME Code,Section XI. However, this

request was denied (NRC letter from J. F. Stolz to H. D. Hukill,

dated October 23,1984). As an alternate proposal, the licensee

plans to remove the internals of the check valve. The licensee is

now in the process of evaluating the safety impact of this action.

The inspector will review the results of the evaluation during a

subsequent inspection (289/85-20-04).

The inspector reviewed the surveillance procedure 1300-3K, "IST of

Valves During Shutdown and Remote Indication Check," Revision 13,

and noted that the stroke timing for MSV-10A and MSV-10B was

incorporated in the procedure.

12.0 Restart Readiness

The NRC Inspection Report 50-289/85-19 documented the TMI-1 Restart Staff

conclusion that there were no adverse conditions that would affect the

safe restart of TMI-1. During this inspection period, the resident

inspector continued to monitor plant status from a viewpoint oriented

toward major equipment operability problems. Based on this review, the

inspector concluded that there still was no adverse condition that would

affect the safe restart of TMI-1 except for sporadic inoperability periods

for one of two channels of source range nuclear instrumentation. This

. problem needs further evaluation prior to restart. Prior to any restart

authorization, the TMI-1 Restart Staff will conduct another review of all

open licensea and NRC issues similar to the restart readiness reviews

previously documented.

13.0 Exit Interview

The inspectors discussed the inspection scope and findings with licensee

management at the exit interview conducted on August 2, 1985. The follow-

ing personnel attended the final exit meeting:

--

J. Colitz, Plant Engineering Director, TMI-1

--

W. County, Quality Assurance Lead Auditor, Nuclear

Assurance Division

--

E. Eisen, Project Engineer, Technical Functions Division

(TFD)

--

D. Hassler, Licensing Engineer, TFD

--

S. Otto, Licensing Engineer, TFD

As discussed at the meeting, the inspection results are summarized in the

cover page of the inspection report. The licensee representatives indi-

cated that none of the subject matter discussed contained proprietary

information. The inspector noted that there were no obstacles (physical

or administrative) to the safe restart of the unit, however, the

potentially unreliable channel of source range instrumentation requires

further evaluation prior to restart.

. . . - - - - - . . . .- - . -

.

.

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l. Unresolved Items are matters about which information is required in order

! to ascertain whether they are acceptable items, violations or deviations.

[ Unresolved item (s), discussed during the exit meeting, are documented in

l paragraphs 5.3.3.5, 7.0, 11.1, and 11.5.

Inspector Follow Items are matters which were established to administra-

tively follow open issues based on licensee or staff commitments from the

TMI-1 restart hearing. Inspector follow item (s), discussed during the

, exit meeting, are documented in paragraphs 5.3.3, 11.1, 11.2, 11.3, and

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ATTACHMENT TO REGION I INSPECTION REPORT N0. 50-289/85-20

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E .I WASHINGTON, D. C. 20555

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OFFICE OF NUCLEAR REACTOR REGULATION .

EVALUATION OF OPERATION OF TMI-1 WITH UP TO

2000 PLUGGED STEAM GENERATOR TUBES

1. Introduction

In the staff's Safety Evaluation Report related to steam generator tube

i repair and return to operation of TMI-1, NUREG-1019, we examined the

effects of plugging up to 1500 steam generator tubes on TMI-1 reactor

thermal and hydraulic considerations and on various transients and

accidents. We concluded that the thermal-hydraulic consequences of such

operation were acceptable, and that accident consequences were bounded

by the FSAR analysis or meet appropriate criteria and were therefore

acceptable.

Since that time, additional tubes have been plugged and the total now

is 1542. The licensee submitted its safety evaluation TDR No. 674,

i Comparison of Steam Generator Tube Plugging with the TMI-1 Design Basis, -

in which it also concluded that plugging 3000 tubes would have no adverse

affect on performance of the steam generators or on licensing basis analyses

for transients and accidents. However, in order to assure conformance with

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present Technical Specifications, the licensee in Revision 1 to TDR No.

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674, limited the applicability of that document to 2000 tubes. The

licensee also concluded that plugging up to 2000 tubes does not involve ,

i an unreviewed safety question as defined in 10 CFR 50.59. '

We have reviewed TDR No. 674 to verify the licensee's conclusions. Our

evaluation is sumarized below.

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2.0 Evaluation

2.1 Core Thermal-Hydraulic Design

The existing TMI-1 safety analysis for Cycle 5 operation is based on a

power level of 2568 ht and a reactor cgolant system (RCS) flow of

106.5% of the design flow of 131.3 x 10 lbm/hr. The licensed TMI-1

power level is 2535 h t and the measured four pump flow is reported to

be 109.5% of the design flow, with 1.5% flow calibration uncertainty,

Plugging of steam generator tubes increases the RCS flow resistance and

results in flow degradation. The licensee has calculated that RCS flow

reduction of 2.0% would result from the plugging of 3000 tubes. Thus,

considering flow uncertainty, this case could result in an actual flow

of 106.0% which is slightly below the existing safety analysis and

Technical Specification limit of 106.5% for four pump operation. We

have considered.the impact of this reduced flow on reactor protection

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system trip limits and capability for full power (2535 Nt) operation,

as discussed below.

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Even though tube plugging results in reduced RCS flow, the flux / flow

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trip function in the TMI-1 plant protection system provides necessary

protection with respect to overpower at reduced flow. This trip

function is specified in the TMI-1 Technical Specifications where the

power level trip setpoint is dependent on the RCS flow rate and power

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imbalance. Flow reduction reduces the power level trip and associated

reactor power / reactor power-imbalance boundaries by 1.08% for a one

percent flow reduction. This is based on the sensitivity of DNBR margin

to power and flow changes and prevents a DNBR of less than 1.3 (limit

value) if a low flow condition should exist due to any malfunction.

For the licensed power level of 2535 Mwt. the safety analysis DNBR

margin and protection system setpoint bases would be preserved for

reduced flow to 105.3% of design flow based on the power / flow versus

DNBR sensitivity relationship. Thus, the existing setpoint for overpower

, protection (105.5%) could be justified for actual flow as low as 105.3%.

However, the flow is limited by current Technical Specifications to a

minimum value of 106.5%. We have also reviewed the licensee's

statements that up 40 2000 tubes could be plugged without reducing flow

below the TS figure, and we concur with that conclusion.

, The licensee has also evaluated the plugging of 3000 tubes with a plugging

ratio of 3:1, i.e., 2250 tubes in OTSG "A" and 750 tubes in OTSG "B". '

The licensee's calculation has determined that this plugging 4

' * configuration would result in loop "A" flow rate approximately 2.5%

smaller than loop B. However, the licensee also states that field data -

during the last cycle had shown that A loop had typically about 3% more

flow than B loop. As a result, the net flow difference due to 3:1 plugging

configuration would be approximately 0.5%, and therefore, the 3:1 plugging e

configuration is acceptable.

In summary, existing reactor protection system setpoints provide DNBR

protection for power operation at 2535 Mwt with flow reduced to 105.3%

even though the flow is limited to a low value of 106.5% by current

Technical Specifications. We conclude that TMI-1 can be operated

within the TS limits on RCS flow with up to 2000 tubes plugged. As part

of the power escalation test program, the licensee will verify by flow

! calibration that the RCS flow remains above existing Technical  ;

, Specification limits.

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2.2 Transient and Accident Analysis

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The effect of plugging up to 3000 steam generator tubes on the

consequences of design basis transients and accidents will be minimal.

The steam generator tubes account for less than 25% of the total RCS

, pressure drop. Plugging 3000 out of a total of more than 30,000 tubes

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would cause the pressure drop through the steam generator tubes to

increase. As discussed above, this increase in pressure drop would

cause the total coolant flow to decrease by approximately 2% as

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. calculated by the licensee. For transients and accidents involving loss

i of forced coolant flow the effect of the tube plugging on flow coast

down and natural circulation flow would also be of little significance,

because the stalled coolant pumps introduce a large flow resistance in

the coolant loops that is substantially greater than the flow resistance

imposed by tube plugging. The effect of the plugged tubes on the ability

of the steam generators to remove heat would also be minimal. During

power operation, secondary system water level would be adjusted upward

as needed to provide for reactor system heat removal. Following reactor

trip the heat transfer surface would be more than adequate to remove

core decay heat.

'

The licensee evaluated the consequences of design basis transients and

accidents and concluded that the evaluations previously submitted in

support of the original license application would still be bounding.

The design basis loss of coolant accidents for TMI-1 were evaluated for

a generic B&W Plant with lowered loops having a power level 9% higher

than that of TMI-1 using approved 10 CFR Appendix K models. The most

severe small break LOCA was detennined to be a 0.07ftr cold leg break.

i This break size would be sufficient to remove decay heat so that steam

generator heat removal would not be required. Uncovery of a region at

i the top of the core was calculated to occur between 1350 seconds and -

1750 seconds. At this time the steam generators would be acting as a

heat source and not be aiding in core cooling. Loss of steam generator

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heat transfer surface from tube plugging would not affect the

consequences of this accident.

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One class of small break LOCA depends on steam generator heat removal

for event recovery. Break sizes of 0.01ft8 and smaller would be unable to

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remove reactor decay heat solely through the break and would require

i steam generator heat removal in the boiler-condenser mode. Previous

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j analyses of small breaks in this size range without tube plugging have

demonstrated that the consequences would not be bounding and that

neither core heatup nor core uncovery would occur. The boiler-condenser

mode of decay heat removal involves condensation of steam generated by

i the core on condensing surface in the steam generators. The

condensing surface would be provided by emergency feedwater EFW spray on

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the outennost tubes and the action of the operator to raise the steam

generator water level to 95% on the operating range, which is well above

the top of the core. The establishment of an adequate condensing

surface above the top of the core is important to provide for reactor

I system depressurization which increases high pressure injection flow

! preventing core uncovery. The staff has concluded that at the 95% level

l an. adequate condensing surface would be available to remove all decay

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heat, with a considerable margin. The plugging of 3000 tubes would

remove 10% of this condensing surface. However, the remaining surface

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would still be more than adequate to remove all decay heat. The staff

j concludes that core uncovery would not occur for breaks in the size range

of 0.01fte and smaller if up to 3000 tubes are plugged.

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For large break LOCA analysis, a critical feature for some plants is the

resistance of steam flow through the reactor coolant loops and steam

generators during reflood. For TMI-I the peak cladding temperature was

calculated to occur during the reflooding period. The analysis did not

i take credit for flow in the reactor coolant loops including the steam

generators during this period and assumed they were completely blocked

by water in the cold legs. Relief of steam from the core was assumed

only through the core barrel vent valves. This assumption would be

unaffected by steam generator tube plugging. The staff concludes that

i the consequences of a large break LOCA would not be affected by plugging

up to 3000 steam generator tubes.

The licensee also evaluated the consequences from non-LOCA transients

and accidents. The reactor system flow coast down curve in the FSAR for

loss of forced flow events was detemined to be still bounding for the

case of 3000 plugged tubes. This detemination was made using the B&W

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PUMP computer code which has been approved by the NRC staff. After the

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coolant pumps were stopped, natural circulation flow would continue

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through the core. The natural circulation flow was calculated to be

negligibly affected by tube plugging.

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The licensee has previously comitted to confim the adequacy of natural

circulation flow in tests at low power during power escalation. This

action is included in the restart license conditions.

Since steam generator secondary side water inventory will increase in

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order to compensate for the reduced heat transfer surface following tube

i plugging, the licensee evaluated the revised inventory in comparison to

! that assumed in the FSAR for steam line break analysis. The FSAR

i inventory assumption of 55,000 lbs was detemined to bound the revised

steam generator water mass by a considerable margin.

1 In the event of loss of feedwater or a main feedwater line break, the

, increase in inventory would provide an additional heat sink until EFW

! could be actuated. More time would be available before steam generator

l dryout could occur. The FSAR analyses would therefore be bounding for

! events of this type.

Although the analysis of a locked _ reactor coolant pump rotor is included

in the FSAR, the licensee did not evaluate the consequences of a

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locked rotor accident accounting for plugging 3000 tubes. The licensee

has stated that the design basis locked rotor analysis, which assumed no

plugged tubes, also assumed very conservative values for loop

resistance, core power peaking, and core flow bypass. Because of these

factors and the small change that tube plugging produces on reactor

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coolant flow, the staff does not expect that the consequences from ,

accidents of this type would be significantly affected. The licensee

j should, however, analyze this event to confim this conclusion.

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The licensee evaluated other design basis events including boron

dilution, coolant pump startup, loss of electric power and steam  ;

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generator tube failure. The licensee concluded that these events would

not be significantly affected by plugging up to 3000 tubes. The staff

agrees with these conclusions. The effect of the plugged steam generator

tubes on reactivity initiated transients and accidents has been reviewed.

The reductions in flow and heat transfer are not large enough to affect

uncompensated operating reactivity changes, CRA withdrawal events from

startup or power conditions, misaligned or dropped CRA events, fuel

handling events or the rod ejection accident. The FSAR analyses for

these events, therefore, remain bounding.

3.0 Conclusions

Based on our review as summarized above, we find that our earlier

conclusions in NUREG-1019 regarding the effects of plugged steam

generator tubes remain valid for up to 2000 tubes. We agree with the

licensee's conclusion that operation with up to 2000 plugged tubes does

not involve an unreviewed safety question as defined in 10 CFR 50.59.

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