ML20031C551

Forwards Summary of Technical Issues for Plant Readiness Review.Util 810929 Precommissioners Review Meeting Rept & Requesting Issuance of OLs for Full 40-yr Terms Also Encl

ML20031C551
Person / Time
Site:	LaSalle
Issue date:	10/02/1981
From:	Delgeorge L COMMONWEALTH EDISON CO.
To:	Schwencer A Office of Nuclear Reactor Regulation
References
2627N, NUDOCS 8110070279
Download: ML20031C551 (49)

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N Commonwealth Edison

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' Address Reply to: Post Office Box 767

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Mr. A. Schwencer, Chief Licensing Branch 2 Division of Licensing U.S. Nuclear Regulatory Commission

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Washington, DC 20555

Subject:

LaSalle County Station Unit 1 1

Plant Readiness Review NRC Occket No. 50-373

References:

1) L. O. DelGeorge letter to A. Schwencer dated October 1, 1981.

2) L.

O. DelGeorge letter to A. Schwencer dated October 2, 1981.

l

3) L. O. DelGeorge letter to A. Schwencer dated September ?8, 1918 [ Control Room Design Review).

4) L. O. DelGeorge letter to A. Schwencer dated September 28, 1981 [ILRT).

5) L. O. DelGeorge letter to A. Schwencer dreted September 28, 1981 [ Fire Protection].

Dear Mr. Schwencer:

The purpose of this transmittal is to provide you with the materials that were developed in preparation for the meeting of September 29, 1981 with the NRC Staff management.

These materials focus attention on those technical issues requiring NRR review or further attention by the applicant, and are presented herein to assure that appropriate management attention is attracted to i

facilitate resolution.

The issues discussed in the report, with few exceptions were discussed with Mr. A. Bournia of your staf f during his site visit of September 21-23, 1981.

To facilitate your review a summary of the issues requiring attention and the organization which, in our opinion, has the next action is provided as Attachment 1 to this letter.

The source document for this summary is the LaSalle County Unit 1 gp/

Pre-Commissioner's Review Report (PRR) which is enclosed.

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, Five (5) copies of the referenced PRR are enclosed for your If you I; ave any questions regarding this docur.ent, please use.

contact me.

I would like to work closely with you to resolve these remaining issues so that the LaSalle County Unit 1 operating licer.se review can be closed.

Very truly yours,

1. )

L. O. De1 George Director of Nuclear Licensing Attachments cc.

NRC Resident Inspector - LSCS 2627N em

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Technical Issues-Requiring Review Summary Resp.

PRR Sect.

Issue Org.

Comment III.A.

SQRT CECO.

PRR Sect.III.E.19-Env. Qual.

NRR' Reference.1 Emer. Plan (Grundy Cty)

FEMA Re-exercise Comp.

III.B.

CSCS Pond CECO.

CRD Return Flow NRR

-Referen e 2 Sec. Cont. Leakage NRR Reference 2 MSIV Leakage NRR T.S. Review Control Room Filters NRR Reference 2 Chlorine Detectors CECO.

D. G. Instrumentation NRR Battery Recharge (12 hrs)

NRR SER Sect. 8.3.1.2 NRR Elect. Pene. Fault. Prot.

CECO.

SER Sect. 9.4.6 NRR Reference 2 DG Pre Lub Pump CECO.

PRR Sect. III.B Control Room Design Review NRR.

Reference 3 Core Exit T/C's PRR Sect. III.D III.C.

Excess Flow Check Valves NRR PRR Sect. III.C ILRT NRR Reference 4

- ~.

ESF Signal Reset NRR Reference 2 i

ODCS NRR IE waiver req'd.

i III.D.

I.A.1.1. - STA NRR Possible Appeal Reg'd.

l IV.A.

Cont. Purge Valve (Surveillance)

NRR Appeal Reg'd.

Supp. Pool Temp. Mon.

NRR Appeal Req'd.

i CRD Accumulators CECO.

T.S. Review App.

I. Tech. Spec.

NRR Appeal Reg'd.

Snubber Tech. Spec.

NRR Appeal Req'd.

Battery Cross Tie CECO.

T. S. Review l

ECCS-LPCS Permissive CECO.

T. S. Review

,f.

IV.C.

Keys & Locks NRR Appeal Requested Fire Protection NRR Reference 5.

I V.A.

Exemption'from 10 CFR 70.24 CECO.

- criticality monit ors 2627N I

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LaSalle County Unit 1 Pre-Commissioners Review Meeting (September 29, 1981)

I.

Introduction - Description of Plant II.

Plant Status A. Construction B. Testing III. Plant Design Review A.

Status of SER Open Items B. SER Commitment Review C. Status of FSAR Commitments D. Status of TMI Commitments E. Unresolved Safety Issues 6

i IV.

Operational Readiness Review A.

Technical Specification Status B.

IE Open Item Status C. Security Program Status D. Fire Protection Program Sta'us E. Emergency ireparedness Prog.am Status i

l F.

Personnel Qualification Sta'ius 5

V.

Conformance With Regulations A. Status of Exemption Requests B. Status of Draf t License f

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I.

Introduction LaSalle County Station is located on a 3060 acre site, 70 direct line miles from downtown Chicago, and 4 miles south of the Illinois River.

The Power Generation complex includes several contiguous b.11 dings located in the Southwest corner of the site.

Rail facilities are supplied by a 7 1/2 mile spur from Ransom, Illinois.

The site is situated 4 miles south of the Illinois River on a flat plain, surrounded by typical Midwestern farms.

The nearest major highway is Interstate 80 (10 miles North).

A County Road (Route 6) is 1/2 mile south of the site and a State Road (Route 170) is 2 miles east of the site.

No pipelines, gas lines or major telegraph l

cables transverse the site.

I The surrounding area is sparsely populated with a population of approximately 11000 within the 10 mile EPZ and 1600 within the low population zone which extends outward 4 miles from the station.

There are no schools, norpitals, prisons, beaches or parks within a 5-mile radius of the site.

The recreation area which was originally laid out adjacent to the LaSalle cooling lake has been changed by the State of Illinois to a fish rearing pond facility, so there are l

no transient visitors expected in that area during seasonal periods.

The cooling lake is approximately (2058 acres including the return i

flume) and is some 218 feet above the Illinois River which was its source of water.

Makeup and blowdown to the river is accomplished through underground pipelines.

The ultimate heat sink is an 83 acre subterranean excavated pond at the west end of the cooling lake.

It connects via gravity flow through the Inke screenhouse to the plant ECCS equipment in the basement of the plant.

There is no flood potential for the LaSalle Plant which sits at elevat19n 710 feet.

Tne cooljng lake has an outflow spillway at elevation 704.3 feet with outf' tow back to the Illinois River.

l The LaSalle units utilize a BWR/5 boiling water reactor designed and supplied by the General Electric Company and a MII containment.

The reactor consists of the reactor pressure vessel containing the core, co.ntrol rods, instrumentation, steam separator and dryer assemblies, jet pumps and the control rod drive mechanisms.

The core contains 764 fuel assemblies and 185 control rods arranged in an upright circular cylinder configuration.

Each fuel usembly consists of an l

8x8 array of rods, 62 of which contain fuci and two of which contain l

water.

Water will serve as both moderater

-d coolant.

The design power level of the reactor is 3323 megawatts.

t The steam and power conversion system will transfer heat energy from the reactor to the turbine generator which will convert it by i.

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r-j conventional means to electrical energy.

Tnis electrical energy is transmitted offsite by four 345-kV transmission lines which use two rignt-of-ways.

One right-of-way extends to the east and the other i

north across the Illinois River.

l The in-house electrical distribution system is segregated into three divisions per unit.

One of these divisions is oedicated exclusively to the high pressure core spray system.

With the exception of a few ventilation systems, such as the service building and the diesel building ventilation systems, the remainder of the ventilation systems exhaust through the ventilation stack, which is common to Doth units.

The vent stack reaches a height of 370 feet above the plant grade.

This stack provides for single poin.t elevated release of effluents.

A 375 foot tall meterological tower was put into service at LaSalle County Station in 1975.

As has been indicated, the LaSalle units are of the BWR-5 design with a Mark II containment.

Improvements associated with this design and unique features provided by Commonwealth Edison include.

1.

Fuel design with lower peaking factors and lower peak clad temperatures than existed for Haten 2, the last BWR licensed.

2.

An improved flow control system which was reviewed with ACRS on the Zimmer docket.

3.

An MSIV-LCS to reduce potential offsite doses due to MSIV leakage.

4.

Improved safety relief valves, currently undergoing additional testing by the BWR Owners Group.

5.

A fully lined suppression pool with external vacuum breakers to minimize steam bypass to the pool air space.

6.

A control room design with improved isolation valve status display, post-accident monitoring and engineered safety feature status display all pre-TMI features, and 7.

A fully engineered remote shutdown capability.

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4 II.A.

CONSTRUCTION STATUS - LA SALLE UNIT I The classical methods of monitoring construction status will show that LaSalle County Station Unit I is completed. All major components are installed, all piping is in place and the electrical work is 99.99% completed. All systems except containment inerting, traversing in-core probe, contaimnent monitoring, and the high radiation samples system have been turned over for pre-operational testing.

To zoom in and look at the project on a microscopic scale reveals that 1

we are not yet construction com'leted. The critica; path to construction p

l completion is the irstallation of the already designcd piping support systems.

This aspect of construction resulted from the new containment load analysis and computational methods.

The final aspects of construction will include hydrostatic tests, installation of insulation, labeling, and painting. Some electrical cable and conduit will require physical changes and some retesting will result. The LaSalle Unit I project will be construction complete hy December 1,1981.

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4 PIPING SYSTEMS SUPPORTS LARGE BORE SMALL BORE i

REACTOR BUILDING OCTOBER 15, 1981 NOVEPEER 15, 1981 D/G BUILDINGS OCTOBER 15, 1981 OCTOBER 15, 1981 T/G BUILDING OCTOBER 15, 1981 NOVEMBER 1, 1981 B

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Preoperational Testing 129 Total Tests (Including 10 Unit 2 Tests) 96 Require NRC concurrence Status of Tests Requiring Concurrence 100% Complete 87 Preops 100% Complete 38 of 64 Preops ready for NRC Review 26 of 64 SD's 100% Complete 21 of 32 SD's ready for NRC Review 17 o f 32 Totals 100% Complete 59 of 96 ready for NRC Review 43 of 96 Total Required Testing Complete 90%

Remaining Testing 3%

held by balancing / flow problems (HVAC) 2%

held to just prior to fuel load (AP-103, VG-101, NR-102) 2%

Construction /TMI backfits still in progress 2%

testing in progress 1%

After Fuel Loading (PT-MS-101C, PT-SI-102, SD-SI-101) i l

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r III.A.

Status Of SER Open Items 1.

Dynamic Qualification

" Qualification Summary of Equipment" submitted Fat 1 ue results submitted 0

Impecance Test Results. submitted Valve Qualification results submitted Audit Findings - substantially resolved (See Section III.E.19) 2.

Environmental Qua'lification NRC Audit - June, 1981 Resolution of Audit Findings - (See Section III.E.10) 1 (1)

Requalification Program submitted Sept.

4, 1981 (ii)

Justification for Interim Operation submitted September 4, 1981

- clarification of failure analysis to be submitted

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October 2, 1981

- NRC teaudit expected October 5, 1981 (iii) Preventative Maintenance Program in place within 90 5

days of NRC safety evaluation 3.

Electrical Separation (Class 1E/non-Class 1E raceways)

RG 1.75 deficiencies exist LSCS cesign justified based on soutdown analysis Confirmatory fault testing to be performed Backfit, if required, prior to startup af ter 1st refueling i

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'Jmergency Preparedness - Long Term (Task III. A.2)

Updated Plan (GSEP) submitted and accepted Exercise conducted Dec.

4, 1980 (1) 1 Unresolved FEMA concern - local (Grundy) County capability.

This county will be re-exerciseds with State (IL) and utility (Dresden Station) personnel on Septemoer 30, 1981.

NRC Emergency Preparedness Appraisal April, 1981

- Appendix A (pre-licensing conditions) awaiting NRC review with 1 exception; i.e. retraining enmplete by October 31, 1981.

- Appendix B (professional recommendations) responded to in July, 1981 - No NRC Staff followup concerns expressed.

- Appendix C (hardware backfits) being tracked as Region III open items with completion dates agreed upon.

Interim ERF's complete Final ERF's complete by 10/82 Public Notification System complete in October, 1981

III.B.

SER Commitment Review Section 2.6.4 (Pg 2-29) - CSCS pond capacity below FSAR description; capacity adequate - FSAR Change Required.

(See Attached proposed FSAR change).

F;ct20n 4.6.2 (Pg 4-30) - CRD leakage (return) flow below FSAR description.

See Section III.E.6 of PRR.

Section 6.2.1 (Pg 6-33) - Secondary containment in-leakage flow can not be verified.

Revise to allow denonstaration of SBGTS capability.

Section 6.2.6.1 (Pg 6-42) - MSIV leakage criterion of 11.5 scfm may not be met.

The mandated value does not give credit 6

for MSIV leakage control system, and could with such credit be increased to 87.5 scfm.

The description of the control room Section 6.4.1 (Pg 6-53) emergency filters is inconsistent with the installed equipment.

Section 6.4.2 (Pg. 6-54) - Calibration problems exist with the installed chlorine and ammonia detectors.

The instruments do not have the design sensitivity.

Require temporary waiver for equipment replacement or permanent removal of the requirement due to remoteness of gas sources (i.e.lP 4 miles).

Section 8.3.1.1 (Pg 8-13) - With respect to diesel skid mounted instruments, it is suggested that qualifying the instrumentation in place be allowed as c.' alternative to arbitrarily moving the instruments.

Section 8.3.1.2 (Pg 8-15) - Eoitorial change required to delete reference to 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> recharge time.

This change has been discussed with and is acceptable to the NRC Staff.

Section 8.3.3. 2 (?g 8-17) - Editorial change to local instrument list is required.

Appeal Required Backfit of fault Section 8.4.1 (Pg 8-20) current protection devices for other than power cables was not agreed to by the applicant and was not discussed at the previous appeals meeting (O. Ross et.al) on this item.

I i

i Section 9.4.6 (Pg 9-12) - It must be assumed that an editorial error exists in that "two 100% seismic - Category I i

ventilation systems" are described for the switchgear rooms, whereas only one such system per room was described in the FSAR and exists in the plant.

i Section 9.6.3.4 (Pg 9-31) - The applicant has provided an equivalent proposed design which if accepted will require revision to the current wording of operating license condition 2.C.20(c).

A description of this design has been provided to A. Bournia (NRR).

(See attachment)

Section 22.II.D.1 (Pg 22-40) - Certain of the commitments identified for completion prior to fuel load (NUREG-051P Supp. 1 Items 7f and 7h) and full power (NUREG-0519 Supp. 1 Item 9b) related to the lighting system are recommo^ded for deferral into the NUREG-0700 long term review of ;ontrol room lighting.

These proposed changes have been discused with the NRC Staff and we understand may be judged acceptable.

Section 22.II.F.2 (Pg 22-90) - The issue of core exit thermocouples is discussed in Section III.D. of the PRR.

I l

I

9.6.3.4 Diesel-Generator Lubrication Oil System In this section of the SER, the NRC is requiring that we install a prelude pump that is driven by a DC motor.

This pump is to De installed in parallel with the engine-driven lube pump and should operate only during the engine cranking cycle until operating oil pressure is reached.

The purpose of this modification is to prevent a momentary lack of lubrication of the various moving parts when the diesel engine is started.

The existing systems prelubricates the turbocharger bearings only.

The other wearing parts of the engine do not receive any lubrication until after the engine starts.

The NRC had previously raised this issue in question 040.117.

In our response we did not cummit to install the prelube pump and provided several reasons for not implementing this modification.

The prelube pump is not mentioned anywhere else in the FSAR.

We do not believe that a prelube pump is needed.

The modification to the lube oil system that we will install to correct the problem of the lack of lubrication from 15 minutes to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after a shutdown will also solve the problem described above.

This modification will consist of installing a 3 GPM pump in parallel with the existing 6 GPM oil circulating pump and changing the piping.

This new pump will be driven by an AC motor and would run continuously.

A DC pump is not needed unless start-ups are delayed for more than 5 seconds af ter loss of AC power.

The LaSalle units start immediately upon loss of AC power.

After this modification is completed, the oil level in the oil coolers and filters will always be kept full regardless of oil temperature and viscosity.

It will also provide contiuous oil circulation through the engine crankshaft bearings in addition to the turbocharger bearings, and the engine I

oil pressure will increase very rapidly after a start-up.

l Therefore, a prelube pump is not needed because the lubrication system will prelubricate all of the main bearings when the 3 GPM AC l

pump is installed.

This modification is superior to the prelube pump audition because the wearing parts of the diesel engine will receive continuous lubrication while the prelube pump only operates during the cranking cycle.

III.C.

Status of FSAR Commitments 1.

Table 6.2-21 (Pg 6.2-93(e)):

Excess Flow Check Valves.

The subject valves have been determined

..vc to isolate within the design limits.

A report under 10 CFR 50.55(e) was made on this subject.

A detailed discussion of the issue is attached.

2.

Preoperational Test Program - Miscellaneous program changes have been and may continue to be processed during the completion of the program.

These changes are discussed with the NRC Staff reviewer (B. Clayton NRR-PTRB) to establish acceptability prior to documentation in the FSAR.

One particular preop test of note is discussed herein because of interest expressed by Region III.

Table 14.2-13 (PT-PC-101):

Integrated Leak Rate Test the Unit 1 ILRT was performed satisfactorily approximately one year ago.

Commonwealth Edison plans to repeat this test in response to our commitment to perform the test within six months of fuel load.

Our proposal is to close out the precperational test and to repeat the test as a surveillance prior to the point in the Unit 1 startup at which primary containment is required.

This request for deferral will be submitted formally.

However, the Region III Office of Inspection and Enforcement has accepted the proposal contingent on NRR Staff acceptance.

In additica, if the ongoing final verification of the containment accident pressure (Pa) results in a revised value, the testing performed will be reviewed and any changes necessary to accommodate a change in Pa will be made prior to reperformance of the test.

3.

Question 31.285:

ESF Signal Reset.

A revision to information previously submitted is being 1

made to expand the list of valves subject to logic revision and to delete the design change for the Feedwater Inlet Check Valves 1821-F032AB due to characteristics of the design which prevent unacceptable change in valve position.

This information had not been accounted for in the original review.

l 4.

Miscellaneous.

(a)

Off-Site Dose Calculation System (NUREG-0654) Class A Model

- The subject model was expected to be operational by j

November 11, 1981 a date which was satisfactory to the NRC Staff.

Difficulties with process computer software development have placed that date in jeopardy.

As a result

U a deferral cf this tasx implementation to a precondition for full power operation will be requested.

This request will be made through the Director of Inspection and Enforcement-Recion III who has coordinated the LaSalle County emergency preparedness appraisal.

2562N

III.C.l.

EXCESS FLOW Cl!ECK VALVE (EFCV) PROBLEM The design of excess flow check valves for low pressure sensing lines was based upon sensing line break immediately downstream of the EFCV in the event of a LOCA.

This assumption resulted in a high differential pressure available across the valve during the above postulated event.

This high AP was specified as available 6P to close the valve in the event of sensing line break immediately downstream of the valve.

During containment integrated leak rate test at LaSalle it was found that the valva would not close if the sensing line break occurred at the instru-ment rather than at a location immediately downstream of the EFCV.

It was recognized that, with a break postulated at the instrument

~

the dP available across the valve was not adequate to c1cse the valve.

An ECN was issued to get the valves modified

• so that the valve will close with a lower available dP, should a break in the sensing line occur, at the instrument itself during a LOCA.

The following table compares the new and old design requirements for EFCV's.

NEW OLD Closing 4P 0.5 psig 1 psig Closing Flow 5 scfm Equivalent of 6.5 gpm water Bleed Flow 0.5 scfm Equivalent of 0.5 gpm water

• The modfication would inc3ude changing spring and poppet assembly.

Low Pressure Sensing Lines (Air)

Per RG-1.ll an excess flow check valve installed in an instrument line of this type should "close or be closed if the instrument line integrity outside containment is lost during normal reactor operation or accident conditions."

During normal reactor opera-tion, these lines may experience a small pressure differential (due to inerting of drywell atmosphere) and, therfore, an instru-ment line break inside the reactor building cannot be of any major consequence.

In the event of an accident, say a LOCA, the valve should close if the instrument line integrity outside containment is lost.

It must be pointed out, however, that RG-1.ll requires valve closure under this condition and does not dictate acceptance criteria on the radiological consequences of such an event.

For assessment of radiological consequences a LOCA and an instrument line break outside drywell are two separate events.

The only requirement that should be met, during LOCA, is that the overall leak rate of the containment and its penetra-tions (excluding main steamlines) not exceed 0.635% per day for the duration of the accident.

The instrument line break, there-fore, does not have to be combined with a LOCA to arrive at the design basis (flow rate and pressure drop) for cloture of the valve as required by RG-1.ll.

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The intent of the RG-1.ll is that although an instrument line break outside containment need not be considered simultaneously with a LOCA for radiological assessment, the break flow through the instrument line should be limited by using an excess flow check valve in the unlikely event the sensing line does break during a LOCA.

This is i:1 line with the philosophy of keeping the dose rate as low as reasonably achievable.

We believe that this intent can be satisfied by replacing excess flow check valves by restriction orifices such that the break flow, in the event of a LOCA and simultaneous sensing line break outside the containment, to a value equivalent to the bleed flow allowed by the excess flow check valve.

9

r III.D Status of TMI Commitments (NUREG-0737)

Item Topic Due Date Schedule I.A.1.1 STA FL (1) 1.A.l.2 Shift Supv. Duties FL (2)

I.A.l.3 Shift Manning FL (2)

I.A.2.1 License Operator Qual.

FL (2)

I.A.2.3 Instructor Qualification FL-2 mo.

(2) 1.A.3.1 Licensing Exams FL (2)

I.B.1.2 Plant Org./Mgt. Assessment FL FL-(3)

I.C.I.

SB LOCA Proc. Review FL-Proc. Review (2) 1st Refuel -

Proc. Update (5)

I.C.2.

Shift Turnover / Relief Proc.

FL FL-(3)

I.C.3.

Shift Supv. Responsibilities FL (2)

I.C.4.

Control Room Access FL (2)

I.C.5.

Feedback of Operating Experience OL (2)

I.C.6.

Verify Operating Activities FL FL-(3)

I.C.7.

NSSS Vendor Review FL-LP Tests FL-(3)

FP-FP Tests FL-(3) 1.C.8.

Emergency Procedures FP FP-(3)

I.D.1.

Control Room Design Review OL (1) 1.D.2.

SPDS 10/82 10/82-(3)

I.G.I.

Training During Low Power Test FL (3)

Note:

NRC Staff requested LSCS input 4 wks. prior to conduct of added test - this schedule will be met.

II.B.1 RCS Vents FP-review (2) 7/1/82-install (2)

OL-proc.

(2)

II.B.2 Plant Shielding 1/1/82 (2)

II.B.3 Post Accident Sampling OL-4 mos./

review (2)

FP-design (2)

FP-Proc.

FL-(3) 1/1/82-mods.

FL-(3)

II.B.4 Trng. for Core Damage Mitigation FL-prog.

(2)

FP-comp.

(2)

II.D.1 SRV Testing FL-prog.

(2)

FL-testing 10/81-(5)

II.D.3 Valve Position Ind.

FL (2) e k

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Item Topic Due Date Schedule II.E.1.1 PWR N/A II.E.1.2 PWR N/A II.E.3.1 PWR N/A II.E.4.1 H2 Penetrations OL (2)

II.E.4.2 Containment Isolation OL OL-(3)

II.F.1.

Accident Monitoring FL-Proc FL-(3) 1/1/82-mods FL-(3)

II.F.2.

Inadequate Core Cooling FL-describe (2)

RG 1.97 (1)

II.G.1 PWR N/A II.K.l.5 Review ESF Valves FL FL-(3)

II.K.1.10 Operability Status FL (2)

II.K.1.22 Aux. Ht. removal FL-proc.

(2)

II.K.1.23 RV Level, procedures' FL (2)

II.K.2.

PWR N/A II.K.3.3 SRV Reports OL-4 mos.

(2)

II.K.3.13 RCIC Initiation 7/1/81 1st Refuel-(3)

Note:

Delay due to delivery of qualified equip., design is' complete.

See NUREG-0519.

II.K.3.15 RCIC Isolation 7/1/81 1st Refuel-(3)

Note:

Delay due to delivery of qualified equip., design is complete.

See NUREG-0519.

II.K.3.16 SRV Challenges 1st Refuel (5)

II.K.3.17 ECCS outages FL (2)

II.K.3.18 ADS 1st Refuel 1st Refuel-(3)

II.K.3.21 Restart LPCS/LPCI lst Refuel 1st Refuel-(3)

II.K.3.22 RCIC Suction 1/1/82 1st Refuel-(3)

Note:

Delay due to delivery of qualififed equip., design is complete.

See NUREG-0519.

II.K.3.24 RCIC space cooling 1/1/82 (2)

II.K.3.25 Power on Recirc. pump seals FP (2)

II.K.3.27 Common reference level 7/1/81 FL-(3)

II.K.3.28 Qual. of ADS accumulators 1/1/82 1/1/82-(5)

II.K.3.30 SB LOCA Methods 1/1/82 1/1/82-(5)

II.K.3.31 Plants specific SB analysis Note:

Requirements are contingent upon results from II.K.3.30 II.K.3.44 Transients with single-failure 1/1/81 (2)

II.K.3.45 Manual

" pressurization 1/1/81 (2)

II.K.3.46 Michelst concerns FL (2)

~

s -

Item Topic Due Date Schedule III.A.l.1 Emergency Preparedness (ST)

FL (2)

III.A.l.2 Upgrade ERF 10/82 10/82-(3)

III.A.2 Emergency Preparedness (LT)

FL FL-(3) 111.D.1.1 RCS leaks outside containment FP (2)

III.D.3.3 12 monitoring FL FL-(3)

III.D.3.4 Control room habitability FP (2) i h

Notes:

(1)

APPEAL REQUIRED (2)

LSCS action complete, awaiting NRC closure - or CLOSED (3)

LSCS actiun in progress (4)

NRC action required (5)

LSCS/BWR Owners Group action in progress Tnose items underlined will not be completed within the Time period defined in NUREG-0737.

v e

sA

III.D. - Item II.F.2 LaSalle Position on In-Core Thermocouples As a result of the Three Mile Island accident, the NRC has perceived c need for all reactor types to use in-core thermocouples to provide an indication of inadequate core cooling.

We feel that the need for in-cora thermocouples should not apply to BWRs for a number of reasons.

This is an issue opposed by all BWR owners.

First, in-core thermocouples provide an indication of inadequate core cooling only for one extremely low probability condition.

That one condition for the BWR is a loss of reactor water inventory, with no normal, emergency, or alternate makeup systems a.allable to supply water to the core.

The BWR has numerous ECCS and normal makeup pumps, any one of which will provide suf ficient water to maintain adequate core cooling.

Any information gained by core thermocouples in the low probability event described above will only backup information from existing water level instrumentation.

In addition, hydrogen indication and high radiation measurements will provide backup indication of inadequate core cooling shortly after it occurs.

With indications already available without thermocouples, the operator will be taking all appropriate actions to restore water level to the core as delineated in the BWR symptom based emergency procedure guidelines.

Second, installation and subsequent upkeep or maintenance of the in-core thermocouples poses a number of problems.

Thermocouple installation will subject plant personnel to increased radiation exposure.

Estimates place this exposure at approximately 100 man-rem, for initial installation on each unit.

This does not include the additional radiation exposure incurred during j

maintenance which may result in an additional 15 man-rem per year.

l Installation and maintenance of the in-core thermocouples will also introduce a significant financial burden to the utilities.

General Electtic has provided an initial cost estimate based on 16 l

thermocouples placed in the Power Range Monitor strings with two control room recorders.

It was assumed that spare containment penetrations were available and multiplexers were not used because of the small number of thermocouples and problems associated with multiplexer qualification.

This conservatively estimated cost for all aspects of initial installation and testing is approximatly

$600K.

The innerent unreliability of available thermocouples for this application make unit outages and the related. replacement power costs a certainity.

This cost has not been balanced by the perceived benefit of this system.

Additionally, it has been suggested that diverse indication of core cooling using in-core thermocouples may result in a reduction in i

l l

risk to the public.

The basis for this lies in the perception that the operator, using the diverse indications available. would be less likely to make an error at a critical moment and thus lessen the probability of core damage.

General Electric has analyzed the effect of the addition of in-core thermocouples in a probabilistic risk assessment performed on a typical BWR, All accideat sequences involving operator action in that risk assessment were evaluated including planned operator actions and emergency backup actions to failed automatic functions to determine in which situation l

thermocouples will help the operator.

Also included was the evaluation of common-mode miscalibration of water level instrumentation and manual initiation of boron injection following an anticipated transient without scram.

Operator action was evaluated using tne Handbook on Human Reliability as a guideline.

When all changes were inserted in the input of the specific PRA event trees, there were eitner negligible or no changes in individual accident sequence frequencies.

The overall effect was no change at all in the core melt frequency and thus no cnange in the risk to the public.

Finally, the majority of the safety goals under consideration by the nuclear industry, incorporate the use of a cost benefit criterion (about $100/ man-rem) designeo to screed out expensive requirements which have little effect on risk to the public.

As stated before, the requirement tor thermocouples is indeed expensive while there is no effect on risk to the public.

in summary, we feel that there is no practl';al need for installation of core thermocouples.

They provide meaningful information for only one extremely low cribability condition, and even then the information has no uemonstrable benef?t to plant operations.

Analysis has shown in-core thermocouples in BWR's to be of no value in reducing public risk at the expense of a nigh industry cost and radiation exposure.

For these reasons, we and all BWR owners feel that there is no practical need to install in-core thermocouples in 8WRs.

This position led the Advisory Committee on Reactor Safeguards to advise the NRC Staff to re-evaluate its position relative to BWR in-core thermocouples (LSCS-OL Review).

Advice, we believe, nas n0t'been taken.

The ACRS restated this position in their-recent review of both the Fermi-2 and Susquehanna Plants.

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4 III.E.

Unresolved Safety Issues l'

1.

Waterhammer (A-1)

(1) 2.

Asymmetric Loads (A-2)

N/4 3.

Steam Generator Tube Integrity (A-3, A-4, A-5)

N/A 4.

BWR Containment Design (A-8, A-39)

(1) 5.

ATWS (A-9)

(2) 1 6.

BWR Nozzle Cracking (A-10)

III.E-1 7.

Reactor Vessel Material Toughness (A-11)

(1)

~

8.

Fracture Toughness (A-17)

N/A 9.

Systerd Interaction ( A-17)

(2)

10. Environmental Equipment Goalification (A-24)

III.E-2

11. Pressura Transient Proteccion (A-26)

N/A

12. RHR Requirements (A-31)

(1)

13. Control of Heavy Loads (A-36)

(1)

14. Seismic Design Criteria (A-40)

(1)

15. BWR Pipe Cracking (A-42)

(1)

16. Containment Sump Reliability (A-43)

(1)

17. Station Blackout (A-44)

(1)

18. Shutdown Decay Heat Removal (A-45)

(1)

19. Jelsmic Qualification of Equipment (A-46)

III.E-3

'0.

Control System Design (A-47)

(1) 2

21. Hydrogen Control (1)

Note:

(1)

The discussion of the item contained in NUREG-0519 is accurate and complete.

(2)

The discussion of the item -contained in NUREG-0519 is accurate, although subsequent improvements or additional reviews are not discussed.

i s.

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III.E-1 BWR Nozzle Cracking (A-10)

Although the discussion of this item in NUREG-0519 13 accurate, a commitment made by Commonwealth Edison to verify CHO seal leakage with the CRD return line cut and cepped has not been met.

This. commitment is documented in response to Q212.145, and required demonstraton of seal leakage jtl80 GPM.

Only 135 GPM has thus far been demonstrated.

Although this problem is being investigated and the required testing will be repeated to verify the initial results, this deficiency is not considered safety-significant.

The leakage criterion was establisned to verify that the water source, i.e. CRD return line flow to the reactor vescal, was not lost by cutting off the return line.

Based on presently available results only 75% of that flow is available.

This is judged to be due to the presently good leak-tightness of the involved seals.

Continued operation of this plant will likely result in some deterioration of the seals with a concommitant increase in leakage flow.

a It should be clearly understood that no transient or accident analysis relies upon this seal leakage to issue proper reactor water level or safe plant shutdown.

T,herefore, although corrective action is being taken and can be discussed with the NRC Staff, this discrepancy should not delay the issuance of the LaSalle County Unit 1 license or startup.

III.E-2 Environmental Qualification of Equipment (A-24)

Commonwealth Edison has undertaken a significant program to verify the environmental qualification of equipment at LaSalle County Station.

That program was intitiated with the review'that preceeded the submittal in November, 1980 of the " DOR Guideline" assessment.

Subsequent to the augmentation of the review requirements in February, 1981, Commonwealth Ecison submitted an assessment against the critieria delineated in NUREG-0588.

This latter submittal was the basis upon which the NRC Staff conducted an equipment qualification audit in June, 1981.

That audit led the Staff to conclude that although the methodology for review of BOP equipment and its subsequent testing appeared adeavate, significant deficiencies existed in tc.e area of the NSSS equip.aent review.

Although improvements continue to be made in the program for review and qualification verification of BOP equipment, the most 1

intensive effort is being devoted to NSSS equipment.

A preliminary i

report in August, 1981 followed by a formal submittal on September 4,

1981 documents the revised NSSS program status.

It is our present understanding that the Staff's preliminary review of the

).

September 4, 1981 submittal was favorable with the exception that tne " Justification For Interim Operation" provided was not sufficiently explicit to allow E component basis assessment of the impact of potential malfunction or failure.

On September.16, 1981 a meeting was held with the Staff to discuss remedial action to resolve this concern.

Agreement was reached on the methodology to correct the September 4 report, and Commonwealtn Edison will make availaole to the Staff on or before October 2, 1981 the agreed upon clarification.

It is also our understanding that the Staff will re-audit the LaSalle County program the week of October 5, 1981.

4 w is as follows The present status of the component revi (as defined in the September 4, 1981 submittal):

NSSS BOP Equip.

Equip.

Total Qualified to NUREG-0588 4

17 21 Under EQ

' Testing 44*

24 68 Awaiting Documentation or Final Evaluation 2

3 5

50 44 94'

• Two items will be replaced with fully qualified equipment; nine items are components of local panels.

III.E-3 Seismic Qualification of Equipment (A-46)

The dynamic qualification (SQRT) review of LaSalle County Station has been in process for more than two years.

The Staff conducted an audit of the program in November, 1980.

Since that time effort has continued to complete the review.

Of particular significance is the fact that extensive in-situ impedance testing was conducteo and the results submitted to verify analytical met

• dology.

A major in-plant test program is also scheduled during the snit I startup testing to verify major components of the equipment dynamic loading.

Furthermore, a fstigue assessmer.

program was undertaken to resolve questions raised by the Staff on the impact of the Mark II Containment hydrodynamic loads on the equipment qualification.

That very extensive program, which the Staff has approved is substantially complete.

The items still in process are discussed below.

Completion of the Seismic Testing of NSSS instruments was 4

set back thirty (30) days due to a retest pf Panel H13P609 at Wyle (Norco).

This retest occupied the last week of August and two weeks in September because an earlier (improperly controlled) test showed the presence of considerable responses from panel parts at

~

frequencies above 33 Hz.

The experimently determined panel responses were to be used as inputs for the mounted instruments so that an instrumented panel test could be run.

When the high frequencies showed up it was necessary to determine the cause (subsequently found to be improperly attached plates, rods, and cover plate at the top of the panel) and then retest.

This has been done and certain instruments are now mounted onto Panel H13P609 for qualification.

Tests scheduled for. September 16, 1981 include the l

following items:

1.

Log Rad Monitor (807E228) 2.

Eagle Signal Time Relay HP.5 (145C3043) 3.

Time delay relay GE #CR 2820 4.

Cutter Hammer Switch (145C3230) 5.

Asco Solenoid #HT 83232 Tests scheduled for September 30, 1981 include the following items:

I 6.

Valve Pre-amplifier (163 C1263 AA)

'7.

Indicating and trip Unit (12982802) 8.

Wide-range monitor 368X102AA 9.

Sensor and converter (part of 7) i I

I l

l l

l L.

m.

}

Several material shortages are still being pursued to provide test specimens for testing; they include, 10.

GE Contractor Model CR Buy offer to NIPSCO 103/205 (45C3209) 11.

Trip, Aux. Unit (238X697)

Buy offer to NIPSCO (Bailey) 12.

2" Hammel-Dahl Globe valve Expected delivery now of NAMCO limit switch January 1982, but trying (SL-32-132) and ACF/WKM to buy them from NIPSCO.

actuator.

13.

Barton level switch Model Expected delivery to

1. /60 enable test on 9-30.

j 14.

GE Indicator & trip unit Buy offer to NIPSCO (129 B2802)

(Bailey)-

f Tests completed; awaiting reports for the following items:

i-1.

Barksdale pressure SIT-M22 1

2.

Barksdale vacuum switch DIT-418SS 3.

Barksdale pressure switen PIH-M340SS I

4 Yarway #4418C level switch 5.

Barton flow switch Model 289A 6.

Pyco temperature element N145C3224 7.

S&K flow transmitter 91 X 16-4-20 (163 C 158P2)

Tnese reports are expecten to be received during September, 1981.

Additional test reports from the Nutech test of panel H13P608 (with instruments) are expected to qualify the following items:

1.

GE Flow Unit:

Square Root Converter 136 B 3051 i

Flow Summer 136 8 3088 Power Supply 136 B 3058 l

It is recommended that the equipment. items still-not l

qualified by test as of October 9, (which include only items 10 thru 14 above) be included in the EQ Program for Class IE Environmental Qualification in accordance with the sequential testing to NUREG l

0588 Category I requirements.

The October 9 date has been selected based upon the schedule for requalification tests being conducted to extend the frequency coverage on Limitorque Operator - Yoke -

Valve.

The Limitorque assemblies are scheduled for retest during the first week of October.

Item 12 above could be included in that lot provided procurement from NIPSCO (Bailey) is fruitful.

As a mechanical item it should be tested separately from a' Class lE electrical test.

i f

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

The rJeferral of testing of items 10 through 14 into the environmental qualification program is justifieu on the same bases as is provided for these specific items given in the " Justification For Interim Operation" submitted on September 4, 1981 and to be updated by October 2, 1981.

2562N

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1

IV.A.

Technical Specifications A.

All Open Items Prioritized (see Attached Summary Report)

Priority 1 - Resolution Required to Accomplish Fuel Load Priority II - Resolution Required to Clarify / Complete Specification Priority III - Resolution Desired to Promote System Reliability.

B.

Appeal Items Expected

1. Containment Purge Valve Testing Requirement (T.S. 4.6.3.5)

The current testing requirement for the purge valves will require frequent testing during plant operaton.

The Type "C" test wnold be required each time the valve is moved.

2. Suppression Pool Temperature Monitors The suppression pool has 14 sensors installed as described in the FSAR.

NRC Staff is requiring 16 sensors per NUREG 0487.

3. Control Rod Drive Accemulator (T.S. 4.2.3.5.6.2)

The CRD accumulator check valves can not meet the 10 min requirement.

The NRC Staff is reviewing a proposal which includes an automatic scram to be installed at the first refueling outage.

i 4.

Main Steam Isolation Valve Leakage (T.S. 3.6.1.2.C)

The plant design includes a MSIV-Leakage Control System and l

as a result a request to allow 87.7 sc#b 95 the allowable leakrate has been presented to the NRC

,_ff.

5. Technical Specification Appendjx "I"

Several Issues have been discussed with the NRC Staff and should be resolved when the results of the discussions are included in the Tech Spec.

1

z.

6. Snubbers (T.S. 4.7.9)

The review of the proposed snubber T.S..

is continuing.

The primary issues include the frequency of visual F

inspections and required neer er of soubbers to be inspecteri.

7. Battery Cross Tie (T.S. 3.8.2.3.C)

The inability to take credit for the battery crnss tie'will result in a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> shutdown should the battery become inoperable.

8. ECCS LPCS Injecion Permissive (T.S. Table 3.3.3-2)

The T.S. permissive setpoint could result in subjecting the low pressure piping to high preseJte.

i I

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LASALLc. TECilNICAL SPECIFICATION UUTSTANDING ITEMS ?H0 Yi 'f Y ^ Technical Specification Action Requ2 red to T.tction No./ Title Description of Relief Required Basis for Relief Resolve Issues 0 +. 2. 3 Zeaple wek Propose d W. Ps av.de M * * '

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IV.C. SECURITY STATUS 1. Installation A. Complete with the following exceptions: 1) addi ti onal cameras - to be completed 11/15/81 2) Efield revision (switchyard)- to be completed 11/15/81 3) miscellaneous problems-resolution ongoing II. Preoperat~.onal Testing. A. The system is 98% turned over for preoperational testing. L. ihe system is 70% preoperat*9nally tested. Exceptions include: i) door retesting 15% 2) contractor access fa-lity 5% 3) uninteruptable power supply 5% 4) miscellaneous 5% lli. Operational Readiness Guard staffing 1) 135 of projected 150 are currently on site. Number required is being reviewed. B. Procedures - LSP's, LXP's & LAP's essentially complece. C. Guard Staf f training per Appendix -B - 50% complete. Not required until 1/1/82. IV. Goals A. System installation and preoperational testing complete 60 days prior to fue' iced. B. Implementation c f site access controls 45 days prior to fuel load. C. Implementation of full security 30 days prior to fuel load. D. These goals still appear to be attainable. V. Problem Areas A. Keys & Locks - we are prepared to meet most restrictive Interpretation if required. B. No other problem areas not previously discussed with either NRR or NRC Region ill and accepted. G G_

IV.D. Fire Protection Program Status The LaSalle County Station fire prefection1 program has been reviewed against cnd satisfies the requirenents of Appendix A ~ to Branch Technical Position ASB 9.5-1. Although the subsequent addition of 10CFR50 Appendix R is not applicable to this plant, it is our understanding that the NRC Staff also assessed the conformance of the program to that regulation, and judged the program adequate in light of these regulatory requirements. That is not to say, however, that LaSalle County meets the letter of 10 CFC 50 Apoendix R. Such details as the periodic hydrostatic test pressure of fire hose and surveillance requirements on installed fire doors while meeting NFPA codes do not meet 10 CFR 50 Appendix R. It is essenti ;, therefore, that the scope of the LaSalle County fire protection 12/lew not be misrepresented. While each of the requirements of the regulation has been addressed and we understand, were judged by the NRC Staff to meet the regulation; the technical deficiencies discussed above could be identified as non comformance items by the regional office of inspection and enforcement unless guidance to that office is not subject to question. The proposed wording of the LaSalle County Unit 1 operating license does not provide such guidance to the Regional authorities. As was indicated the LaSalle County fire proteciton program has been judged acceptable by the NRC Staff. A comprehensive review of the agreements reached during the course of the Staff review and documented in NUREG-0519 has identified only one unresolved deficiency. The single. deficiency is the testing schedule for the fire stops described in SER Section 9.5.6.3. This test is not expected to be completed until January 4, 1982. A similar review of all FSAR commitments have identified two potential deficiencies, which are presented here for completeness although a thorough assessment of their significance is l not yet complete. The two items are: l 1. The FSAR (Page 9.5-13) commits to install ion detection systems in all inlet and outlet plenums of air handling l systems. Certain plenums have been identified to be without such detectors and are being evaluated to determine whether they fall within the scope of the commitments. 2. The FSAR (Page 9.5-14) states air intakes are a minimum 100 feet from exhaust and smoke vents. At least one apparent violation of this commitment: has been identified. A complete review is in process to determine the scope of this potential problem and what, l if any, modifications are necessary to satisfy the commitment. l I

These two issuses will be evaluated in September, 1981 and i the results of that evaluation reported to the NRC Staff. At this time it is not known whether remedial action is required. 2562N 0 l l 9 l i l l

~ l 3 7 f LIV.F. Personnel Qualification Status Fuel Load Requirements - Unit 1-l 1 LSCS - Pos. .TS..- Pers. Pers. I Reg'd Req'd Av'a il. ( min ). Snift. Engineer (SRO)- 1 5 6 i Shift Fore.(SRO) in Control. Room 1 5 10 SCiii./3TA 1 5 5 Nucl. Sta. Oper (RO) 2 10 14 Staff (SRO)_ 0 11 Equip. Operator (EO) 1 -0 6 i Equip. Attendant (EA) 3 15 18 s. Note: (1) NRC Licensing Exam Expected Results 27 RO Candidates-1 Failure. i 37 SRO Candidates 2 Failures i 1 Downgrade to R0 i i r i I 3 f y b [

C m %Es; BAsav en waass m meraq a.aues., exrecrew ranm.wp any NRc exano s. Doas mr mccuca osaa.rs or Sarr.17,txipet 68 Anrts) EJ(ener s Fo g tl RO 7.140 cnAlv/pA7'ff. TABLE L.3-1 SCHEDULE FOR INITI AL AND REPLACPNEffr TRAINING PROGRAM Jpg. 36,1981. Sc97. SO !98 t. s FtJEL IDAD '^ '--- .aer 4 IPDIVIDUALS PER PRE-FUEL IDAD Tr :1 M. 1991 fM1T RO. f1AMI (pnT Pn. FWAMI SWIFT POS. PROVIDES Sorr CrENT sutrT pg, g J COVERAGE 3 SHIF"T/DAT 9 9 ed 9 8 RRS./ SHIFT. b b b b 5 IND. PER SHIFT POS. d d N p d s. w u .3 PROVIDES FOR COM91NED e g g g m en e g q q TRAINING, SICENESS AND g n,, g g g g g 3 g q g g g g g g g C c3 f; VACATION COVERAGE. g c_e n a e. N 3 D M 3 D o 3 d D t$ t3 M 3 D 3p g h M 5 . 5 d 5 L . 5 J 5 '^ 5 0 D 0 L. Q 0 E 0 0 ~' ~ a N 5 . 5 o E N 5 d RfCUIRFD SHIFT CONPLINEtrr p I" 6 0 6 5 6 6 0 6 5 6 6 0 6 5 6 1 SHIFT ENG'R (SRO) 0 5 0 0 NA 1 SRIFT FORE (1) (SRO) (a) (b) (d) IN COtrT. GOOM 0 X 0 0 NA .JP" 0 ,JP" 5 6 .M" 0 .,ler" 5 6 y ') .p" 5 6 lL fo /*

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0 6 (g) (a) (b) (c) E 2 NUCLEAR STA. OPER. (RO) 0 15 0 0 NA Je* O 12 10 12 12 0 .W" 10 R" .W 0 bed" 10.w-5 14 ff f f" 11' / S~ o f' O STAFF, (SRO) 0 11 0 0 NA 11 0 11 0 11 11 0 11 C 11 11 0 71 0 II NON-LICENSED PERSOmMEL~~ (a) (b) (c' 1 HQUIP. OPER. 0 0 0 0 NA .h" 3 .,b" 0 6 JP" 0 J4"' O 6 ,p" 0 y 0 6 7 a /e F Q (b) (*) (t) 3 EQUIP. AT"END. 0 y',30 0 NA A" 30 15 18 .JP-6 15 14 5 6 ,,p. 15 18 Y f S 1 le 11 FOOTMOTES: (1) If the Shift Tech. Advisor holds SRO Licenae, he may fulfill the requirements nf the FRO in tha control roce during normal operations. During accident, the S.T.A. becvweg advisor and the Shift Fnqineer r epor t s to t he cent. rone and assumes cenmaand f unct ions. (2) In training or OJT in support of Pre-op Te=ts. y} z, 187TE: The folicneing footnotes reflect assumed manning chang.s due to promotiong, attrition, ud a license f ailure rate of 'd j approx. 104. 5,, 1 SC FAILJ (SRO) (C) ., N Promote 3 rn t ri Nso 1 SP FAILS (3RO)

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+ V. Conformance With Regulations A. Status of Exemption Requests The exemptions discussed in NUREG-0519 accurately reflect requests made by CECO. and will not be discussed further. An exemption will need to be requested to 10 CFR 70.24 regarding crif icelity alarm systems for unirradiated (new) . fuel. Although an exemption has been granted as a part of the Special Nu: lear Materials License for LaSalle County, we were recently advised that the exemption must be applied far to extend over the term of the operating license. B. Status of Draf t License The draft LSCS-1 license was discussed informally with the NRC Staff and clarifying recommendations made at that time. The discussion items are summarized in the attached table. l. I l.

Table V.8 LSCS-1 Draft License Review Section 1 - no commer.t (N/C) Section 2.A - N/C Section 2.B(1) - N/C Section 2.B(2) - See Section V.A. of PreCommissionar's Review Report (PRR) for discussion of exemptior. to 10 CFR 70.24 Section 2.B(3)(4)(5) - N/C Section 2.C - Item (1) - N/C Item (2)-- App. A Tech Specs - see Section IV.A of PRR App. B. Tech Specs - LSCS input provided Jan. 1981 - no formal NRC Staff responre. New Environmental Protection Plan expected week of 9/21/81 - LSCS review not yet begun. Item (3) - N/C Item (4) - See Section IV.D. o f PRR Item (5) - CECO. objects to RG 1.97 backfit; however, wording of condition is acceptable. Item (6) - N/C Item (7) - N/C Item (8) - N/C Item (9) - This item has been addrcssed. CLOSE Item (10) - This 1+.em has been addIcssed. CLOSE Item (11) - Editorial clarification required to allow natural circulation during startup testing. Item (12) - part 12(b) should be changed to reflect current schedule, i.e. 120 days from receipt of NUREG-0803. Item (13) - N/C Item (14) - N/C Item (15) - ibis item is covered in Technical Specification

ther+ fore, the need for license condition is questionable.

Item (16) - N/C Item (17) - N/C Item (18).- N/C Item (19) - N/C ) Item (20) - Part 20(a) should allow completion " prior to startup following first refueling." Part 20(b) should consider design proposal provided A. Bournia (NRC) on Sept. 22, 1981. Part 20(c) should allow qualification in place as alternat!ve t'o relocating ( diesel instrumentation. - Item (21) - N/C Item (22) APPEAL REQUIRED. Application of RG 1.63 to other than power circuits previously addressed in NRC Staff Question 40.106 is regulatory ratchet not previously discussed with the applicant. l 4 v.--. r e. m

~. v - Item (23) - N/C Item (24) - This' item has been addressed. CLOSE Item (25) - See Section IV.C of PRR Item (26) - The_ June 30, 1982 EQ completion date should be revised to reflect current position of Commission at license issuance. Item (27) - NUREG-0737 [ majority of items-being reviewed for closure by IE] (a) STA - APPEAL REQUIRED See Section IV.A of PRR (b) I.A.l.2 - N/C (c) I.C.2. - N/C (d) I.C.6. - N/C (e) I.C.7. - N/C (f) I.C.8. - N/C (g)~I.D.1. - A revision to NUREG-0519 Supplement 1 Appendix C Items 7(f), 7(n) and 9(b) are required concerning control room lighting (h) I.G.1 - N/C (i) II.B.3 - N/C (j) II.B.4 - Scheduled for completion prior to fuel loading; therefore, conditioned issuance of Full Power License for Degraded Core Training not required. (k) II.D.3 - N/C (1) II.F.1 - N/C (m) II.F.2 - APPEAL REQUIRED - see attachment to Table V.B. (n) II.K.l.5 - N/C (o) II.K.l.22 and II.K.3.22 - N/C (p) II.K.3.15 - Schedule for completion should be as oefined in NUREG-C519. (q) II.K.3.18 - Although the equipment backfit conditioned is acceptable, potential changes to plant emergency procedures have not yet been evaluated. (r) II.K.3.21 - Should allow completion " prior to startup following first refuel outage. (s) II.K.3.25 - N/C (t) II.K.3.27 - N/C (u) II.K.3.28 - N/C (v) III.A.1.2 - N/C (w) III.A.2 - N/C (x) NUREG-0519, App. C. task A N/C i Secticn 2.D - N/C Section 2.E - N/C Section 2.F - N/C Section 2.G - inc date of expiration should be 40 years from date of operating license issuance (see L. O. De1 George letter to H. R. Denton dated September 17, 1981 - copy attached). 2562N ,.. ~.. - -.

+ / Commonwealth Edison [ - 'h one First Naborti Ptara. Chic go. Ilknois \\ V T/ Address Reply to: Post Office Box 767 g (j Chicagd. lilinois 60690 s September 23, 1981 Mr, Harold R. Denton, Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555

Dear Mr. Denton:

Commonwealth Edison Company anticipates receiving operating licenses for its LaSalle County Nuclear Power Station, Units 1 and 2, this fall and next year. The purpose of this letter is to request the Nuclear Regulatory Commission to issue each of these operating licenses for a full term of 40 years each, running from the date of the issuance of the licenses. The requested 40-year term would be consistent with the safety reviews conducted by the Energy Act and the NRC regulations. The NRC's past practice has been to issue an operating license for a term of 40 years, which is backdated to the issuance of the construction permit rather than starting with the issuance of the operating license itself. Because the time required for the construction of nuclear power plants has steadily increased over the past few years,.the Commission's practice of backdating has resulted in the steady erosion of authorized operatino oeriods for newer plants. (See Attachment 1). This practice of reducing the lifetime of operating licenses is apparently unintentional and arbit'.ary. It is not required for the safety of nuclear power plants, nor is it in keeping with the intent of tne Atomic Energy Act. For LaSalle County Nuclear Station, following the past practice of backdating operating license would result in an effective duration of only 32 years, a 20% reduction in the i authorized operating life of the Station. This result is not compelled by the NRC Staff's thorough safety and environmental review of the LaSalle units. The Staff did not base its reviews on a fixed number of years from the date of the construction permit. Commonwealth Edison is unaware of any safety or environmental considerations which require limiting the effective duration of the LaSalle operating licenses to a period of less than 40 years. Section 103(c) of the Atomic Energy Act of 1954, 42 U.S.C. $ 2133(c) (1976), authorizes the Nuclear Regulatory Commission to issue commercial operating licenses for a "specified period...but N . p y1_ 8 Ii o 0 DML

~

• e not exceeding 40 years."

The 40 year limitation in the statute', ? wever, was not dictated by a concern for safety or for the e' ironmental effects of centinued operation. In fact, a close study of the legislative history to Section 103(c) reveals that it was economic considerations which were behind the decision to establish a 40 year limit. Interestingly, the first proposal in April, 1954, to' amend the Atomic Energy Act of 1946 provided for a 25 year limitation on operor.ing licenses. (A Proposed Act to Amend the Atomic Energy Act of 1946, Joint Committee on Atomic Energy, 83d Cong., 2d Sess. 21 (Comm. Print April 1954 reprinted in Legislative History of the Atomic Energy Act of 1954, at 81 (1955).) However, in hearings held s before tne Joint Committee on Atomic Energy in May, 1954, a representative of interested public utilities, E. H.

Dixon, testified that the 25 year limitation would discourage nuclear power plant construction projects.

(Hearings Before the Joint Committ=e on Atomic Energy, 83d Cong., 2d Sess. 203-31 (May 11, 1954) (statement of E. H. Dixon) reprinted in Legislative History of the Atomic Energy Act of 1954, at 1864-1865 (1955).) Apparently because of tnis testimony, tne Joint Committee amended the propcseo Dill and ~ expanded the 25 year maximum on operating licenses to 40 years. (Draft In Bill Form, Joint Committee Print, 83d Cong., 2d Sess. 41 (May 21, 1954) reprinted in Legislative History of the Atomic Energy Act of 1954, at 297 (1955).) It was this latter proposal whicn became law on February 17, 1954. Pub. L. No. 703-1073, 68 Stat. 919 (1954). From the legislative history of Section 103(c), it seems fairly clear that the intent of Congress was to provide a full 40 year licensing term so that public utilities would not be discouraged from taking on the costly burdens of constructing nuclear power stations only to find the licenses expire when their investments still had economic usefulness. The fact that modern / power plants are more expensive and take longer to build and license than older plants increases the justification for allowing a successfui applicant and the public it serves the full economic benefit of the 40 year term originally intended by Congress. The NRC regulations which implement Section 103(c) carry forth the intent of the statute by prescribing procedures which insure a full term of 40 years to an applicant who meets the necessary safety and environmental requirements of the Commission. In particular, 10 CFR 50.51 entitled " Duration of License," provides: i Each license will be issuer) for a fixed period of time to be specified in the licerse but in no case to exceed 40 years from the date o .ssuance. Where the operation of a r facility is involvea the Commission will issue the license for the term requested by the applicant or for the estimated useful life of the facility if the Commission determines that the estimated useful life is less than than term requested....

e This regulation clearly requires the NRC to grant Commonwealth Edison's request for 40 year operating licenses unless the useful life of-LaSalle County Station is determined to be something less. In addition, the language of 5ection 50.51 states that the license should run "from the date of issuance," not from a date prior to the issuance. 10CFRj50.56isnotinconsistentwith10CFR50.51. Sectionj50.56referstothe" conversion" of a construction permit to an operating license. But in NRC practice there has always Deen a clear distinction between a construction permit and an operating license. Construction permits and operating licenses have their own distinct terms and conditions, including different environmental monitoring requirements, different safety inspection schedules, and different time limits. There is no more reason why the term of the construction permit should be reflected in the term of the operating license than there is that a particular monitorjng program, appropriately developed for construction activities, should be included in the operating license technical specifications.

• Moreover, the rule governing duration of operating licenses is found in 42 U.S.C. )?l33, while the need for time limits for construction permits is derived # rom a completely different source.

See 42 U.S.C.$2235. Therefore, there is no logical reason why " conversion" of a construction permit into an operating license should require subtracting apples (the time for construction) from oranges (the time for operation). A fair appreciation of the enormous effort which nas gone into the construction and licensing review of the LaSalle County Nuclear Station, and a careful reading of the Atomic Energy Act of 1954, the legislative history, and the regulations supports the view that, once construction is completed, there is really no reason why anything less than a full 40 year term should be granted. Arbitrarily foreshortened license terms do not se{ve the best intersts of the NRC, the applicant or the public._ Commonwealth Edison asks that the NRC Staff grant its request to have the operating licenses for the LaSalle County Station issued for full 40 year terms beginning with the dates of issuance. In the event the Staff cannot support our position, we ask that our request be forwarded to the Commission for its consideration and that we be given an opportunity to address the Commission in support of our request. Commonwealth Edison would like to stress, however, that its. principal concern lies in the timely licensing of the LaSalle County Station. We do nat want this s b "%[h

request to result in any delay in this licensing process. Sincerely, L. O. DelGeorge Director of Nuclear Licensing cc: Martin Malsch Colleen Woodhead 4 1. The statute and regulations do provide for renewal of licenses upon expiration. 42 U.S.C 2133; 10 CFR 50 51. But re-licensing a nuclear power plant would be an enormous, uncertain undertaking which can not be rtgarded as a 1 satisfactory answer to Commonwealth Edison's present request for the full-term, 40-year operating licenses to which it is entitled by law. i l 2538N l l l l l _f e

~ ^- y O O NUCLEAR UNITS ARRAN D CHROMOLOGICALLY BY DATE OF OPERATING LICENSE g 'SEP 2 3 m* EFFECTIVE LIFETIME NRC OF A 40-YEAR DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OPERATING LICENSE C.P. O.L. NUMBER 50-10 Commonwealth Edison Dresden - 1 5-04-56 9-28-59 3G yrs. 7 mos. Co. 50-456 Yankee Atomic Yankee-Rowe 11-04-57 7-09-60 37 yrs. 4 mos. Electric Company 3 50-213 consolidated Edison Indian Pt - 1 5-04-56 3-26-62* 34 yrs. 1 mo. Co. of N.Y. 50-133 Pacific Gas and Humboldt Bay 11-09-60 8-28-62 38 yrs. 2 mos. Electric 50-155 Consumers Power Big Rock Point 5-31-60 8-30-62* 37 yrs. 9 mos. Co. 50-206 Southern California San Onofre - 1 3-02-64 3-27-67 37 yrs. Edison Co. 50-213 Connecticut Yankee Conn. Yankee 5-26-64 6-30-67 36 yrs. 9 mos. Atomic Electric Co. 50-409 Dairyland Power Coop. La Grosse 3-29-63 7-03-67** 3S yrs. 9 mos. 50-219 Jersey Central Power Oyster Creek 12-15-64 4-09-69 35 yrs. 7 mos. & Light 50-220 Niagara Mohawk Nine Mile pt - 1 4-12-65 8-22-69 35 yrs. 8 mos. Power Corp.

• Date for provisional operating license.
  • Date for provisional operating authorization.

NUCLEAR UNITS ARRA b CHRONOLOGICALLY I BY DATE OF OPERATING LICENSE i EFFECTIVE LIFETIME i NRC DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OF A 40-YEAR OPERATING LICENSE NUMBER C.P. O.L. 50-244 Rochester Gas and Ginna 4-25-66 9-19-69* 36 yrs. 1 mo. Electric Corporation i 50-237 Commonwealth Edison Dresden - 2 1-10-66 12-22-69 36 yrs. 1 mo. Co. 50-251 Carolina Power and Robinson - 2 4-13-67 7-31-70 36 yrs. 7 mos. Light 1 l 50-263 Northern States Monticello 6-19-67 9-08-70 36 yrs. 7 mos. Power Co. i 50-266 Wisconsin Electric Point Beach - 1 7-19-67 10-05-70 36 yrs. 9 mos. .I Power 50-245 Northeast Utilitias Millstone - 1 5-19-66 10-07-70 35 yrs. 7 mos. i 50-249 Commonwealth Edison Dresden - 3 10-14-66 1-12-71 35 yrs.10 mos. Co. ) 50-254 Commonwealth Edison Quad Cities 1 2-15-67 10-01-71 35 yrs. 4 mos. Co. 50-265 Commonwealth Edison Quad Cities 2 2-15-67 3-31-72 34 yrs.10 mos. t Co. 50-301 Wisconsin Electric Point Beach 2 7-25=68 5-25-72 36 yrs. 2 mas. Power l

• Date for provisional operating license.

l l

q. n NUCLEAR UNITS ARRANGED CHRONOLOGICALLY BY DATE OF OPERATING LICENSE I EFFECTIVE LIFETIME NRC OF A 40-YEAR DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OPERATING LICENSE C.P. O.L. I NUMBER j 50-280 Virginia Electric Surrey - 1 6-25-68 5-25-72 36 yrs. 1 mo. and Power i l 50-293 Boston Edison Pilgrim - 1 8-26-68 6-08-72 36 yrs. 1 mo. 50-250 Florida Power and Turkey Pt. -3 4-27-67 7-19-72 34 yrs. 9 mos. Light i 50-309 Maine Yankee Atomic Maine Yankee 10-21-68 9-15-72 36 yrs. 1 mo. ] Power Co. 50-255 Consumers Power Palisades 3-14-67 10-00-72* 34 yrs. 5 mos. I 1 50-281 Virginia Electric Surrey - 2 6-25-68 1-29-73 35 yrs. 5 mos. I and Power l 50-269 Duke Power Co. Oconce - 1 11-06-67 2-06-73 34 yrs. 9 mos. j 30-270 Duke Power Co. Oconee - 2 11-06-67 2-06-73 34 yrs. 9 ces. l t ) 50-271 Vermont Yankee Vt. Yankee 12 11-67 2-28-73 34 yrs. 9 mos. 50-295 Commonwealth Edison Zlon - 1 12-26-68 4-06-73 35 yrs. 6 mos. I Co. 50-251 Florida Power Tut' key Pt. 4 4-27-67 4-10-73 34 yrs. and Light 50-285 Omaha Public Power Ft. Calhoun - 1 6-07-68 5-24-73 35 yrs. 4 District

• Date for full power authorization, P.O.L. issued 3/24/71.

i

~~ ..A-4 D NUCLEAR UNITS ARRAN b CHRONOLOGICALLY ~ BY DATC OF OPERATING LICENSE NRC EFFECTIVE LIFETIME DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OF A 40-YEAR NUMBER C.P. O.L. OPERATING LICENSE nw i j 50-259 Tennessee velley Browns Ferry 1 5-10-67 6-26-73 34 yrs. 1 mo. Authority a i 50-277 Philadelphia Electric Peach Bottom 2 1-31-68 8-08-73 34 yrs. 5 mos. i Co. 50-282 Northern States Prairie Island 6-25-68 C-09-73 34 yrs.ll mos. Power Co. 2 1 50-247 Consolidated Edison Indian Point 2 10-14-66 9-28-73* 33 yrs. 1 mo. Co. of N.Y. 30-304 Commonwealth Edison Zion 2 12-26-68 11-14-73 35 yrs. 1 mo. Co. i 50-305 Wisconsin Public Kewaunee 8-06-68 12-21-73 34 yrs. 8 mos. Service Corp. 30-267 Public Service Co. of Fort St.

5. rain 1 9-01-68 12-21-73 34 yrs. 9 mos.

Oklahoma l 30-298 Nebraska Public Cooper 6-05-68 1-18-74 34 yrs. 5 mos. Power District 30-331 Iowa Electric Light Arnvid 6-22-70 2-22-74 36 yrs. 4 mos. & Power Co. 30-289 Metropo_o. tan Edison Three Mile Island - 1 5-18-68 4-19-74 34 yrs. 1 mo. 4 a

• Dato for full power authorization, O.L. issued 10/19/71.

.A-5 ~ - c. m NUCLEAR UNITS ARRANT > CHRONOLOGICALLY BY DATE OF OPERATING LICENSE EFFECTIVE LIFETIME NRC DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OF A 40-YE.%1 NUMBER C.P. O.L. OPERATING LICENSE 30-313 Arkansas Power Ak. Nuclear 1 12-06-68 5-21-74 34 yrs. 6 mos. & Light i 50-260 Tennessee Valley Browns Ferry 2 5-10-67 6-28-74 32 yrs.ll mos. 4 s 1.stthority 30-287 Duke Power Co. Oconee - 3 11-06-67 7-19-74 33 yrs. 4 mos. t 50-317 Balt..more Gas and Calvert Cliffs 1 7-07-69 7-31-74 34 yrs.ll mos. Electric 50-321 Georgia Power Hatch - 1 9-30-69 8-06-74 35 yrs. 2 mos. 30-312 Sacramento Municipal Rancho - Seco 1 10-11-68 8-16-74 34 yrs. 2 mos. Uctlity District 30-333 Power Authority of James A. Fitzpatrick 5-20-70 10-17-74 35 yrs. 7 mos. State of N.Y. 10-315 Indiana & Michigan Cook - 1 3-25-69 10-25-74 34 yrs. 5 mos. Electric Co. 10-306 Northern States Prairie Island 2 6-25-68 10-29-74 33 yrs. 8 mos. Power Co. 10-324 Carolina Power and Brunswick - 2 2-07-70 12-27-74 35 yrs. 3 mos. Light I 1

A-6, NUCLEAR UNITS ARRANd CHRONOLOGICALLY BY DATE OF OPERATING LICENSE 1 NRC EFFECTIVE LIFETIME l DOCKMT COMPANY NUCLEAR UNIT DATE OF DATE OF OF A 40-YEAR NUMBER C.P. O.L. OPERATING LICENSE 1 1 1

0-336 Northeast Utilities Millstone - 2 12-11-70 8-01-75 35 yrs. 4 mos.

0-344 Portland General Trojan 2-08-71 11-21-75 35 yrs. 3 mos.

1 Electric Co. 0-286 Power Authority of Indian Pt. -3 8-13-69 12-12-75 33 yrs. 3 mos. State of N.Y. 0-334 Duquesue Light Co. Beaver Valley - 1 6-26-70 1-30-76 34 yrs. 5 mos. 4 0-335 Florida Power E Light St. Lucie - 1 7-01-70 3-01-76 34 yrs. 6 mos. 0-296 Tennessee Valley Browns Ferry 3 7-31-68 7-02-76 32 yrs. 1 mo. Authority 0-318 Baltimore Gas & Calvert Cliffs 2 7-07-69 11-13-76 32 yrs.11 mos. Electric 0-325 Carolina Power Brunswick - 1 2-07-70 9-08-76 33 yrs. 5 mos. & Light 0-302 Florida Power Co. Crystal River 3 9-25-68 12-03-76 31 yrs.10 mos. 0-272 Public Service Salem - 1 9-25-68 4-06-77* 31 yrs. 7 mos. Electric & Gas Co. 0-346 Toledo Edison Co. Davis-Besse - 1 3-24-71 4-22-77 33 yrs.ll mos'. 0-348 Alabama Power Farley - 1 8-16-72 6-25-77 35 yrs. 2 pos. l Date for full power authorization, O.L. for 1% power issued 8/13/76.

p, .; q,A-7 i NUCLEAR UNITS ARRANGED CHRONOLOGICALLY BY DATE OF OPERATING LICENSE 1 EFFECTIVE LIFETIME NRC OF A 40-YEAR 1 DOCKET COMPANY NUCLEAR UNIT DATE OF DATE OF OPERATING LICENSE C.P. O.L. NUMBER 50-338 Virginia Electric North Anna - 1 2-19-71 11-26-77 33 yrs. 3 mos. & Power Co. l 50-316 Indiana and Michigan Cook - 2 3-25-69 12-23-77 31 yrs. 3 mos. Electric Co. 50-320 Metropolitan Edison Three, Mile Island - 2 11-04-69 2-08-78 32 yrs. 4 mos. i Co. i 50-366 Georgia Power Co. Hatch - 2 12-27-72 6-13-78 34 yrs. 6 mos. 50-368 Arkansas Power & Arkansas Nuclear 12-06-72 7-18-78 34 yrs. 7 mos. One-2 Light Co. 50-339 Virginia Electric & North Anna - 2 2-19-71 10-11-80 30 yrs. 4 mos. Power Co. 50-364 Alabama Power Co. Farley - 2 2-16-72 10-23-80 31 yrs. 4 mos. 50-327 Tennessee Valley Sequoyah - 1 5-27-70 10-23-80 23 yrs. 7 mos. Authority i 50-369 Duke Power Co. McGuire - 1 2-28-73 6-29-81* 31 yrs.10 mos. 50-311 Public Service Salem - 2 9-25-68 Expected 81** i Electric & Gas

• Date for full power authorization, O.L. issued on 4/18/80 for low power testing.
  • Zero power O.L. issued 1/23/81.

A-W ~i NUCLEAR UNITS ARRAN CilRONOLOGICALLY DY DATE OF OPERATING LICENSE 4 I EFFECTIVE LIFETIME NRC OF A 40-YEAR DOCKET COMPANY NUCLEAR UNIT DATE OF DATE Op OPERATING LICENSE C.P. O.L. HUMBER 50-361 Southern California San Onofre - 2 10-18-73 Expected 81* 50-328 Tennessee Valley Sequoyah - 2 5-27-70 Expected 81* i Authority 1 i 4 f i i I i i I l

• O.L.'s have been Commission Agenda items in 1981.

Source: Compiled from NUREG-0652, Vol. 1, No. 1, Facilities License Application Record, Data as of 4/1/81, NRC j (1981); Commercial Nuclear Power Plants, Ed. No. 13, i NUS Corp. (1981); Actual Dockets of NRC; and, The l Energy Daily (June 30, 1981). ,}}