ML19345C150

Forwards Request for Addl Info Required to Complete NRC Evaluation of Application for Operating Licenses for Facilities.Response Should Be Submitted within 6 Wks

ML19345C150
Person / Time
Site:	Comanche Peak
Issue date:	11/20/1980
From:	Tedesco R Office of Nuclear Reactor Regulation
To:	Gary R TEXAS UTILITIES ELECTRIC CO. (TU ELECTRIC)
References
NUDOCS 8012040017
Download: ML19345C150 (25)

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UNITED STATES 8

NUCLEAR REGULATORY COMMISSION n

.E WASHINGTON, D. C. 20066 3,

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Docket Nos. 50-445 and 50-446 g

WV20 W g;O w<

Mr. R. J. Gary N:

Sh Executiva Vice President and j

General Manager

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3 g-Texas Utilities Generating Company

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2001 Bryan Towers B

t Dallas, Texas 75201 US 3

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR COMANCHE PEAK STEAM ELECTRIC STATION, UNITS 1 AND 2

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Enclosed is a request for ?.iditional information which we require to complete our evaluation of your app'.ication for operating licenses for Comanche Peak Steam Electric Station, Units 1 and 2.

This request for additional information is the result of our continuing review by the Reactor Systems Branch, the Sitirg Analysis Branch, and the Hydrologic and Geotechnical Engineering Branch. Please amend yaur FSAR to include the information requested in the Enclosure.

Your. response to the enclosed request for additional information should be submitted within six (6) weeks. Should you have questions concerning this request for additional information, please contact us.

Sincerely.

-N Robert L. Tedesco Assistant Director for Licensing Division of Licensing

Enclosure:

Request for Additional Information cc w/ enclosure:

See next page B;012040 %

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Mr..R. J. Gary Executive Vice President and General Manager NOV 2 01980 Texas Utilities Generating Company 2001 Bryan Towers Dallas, Texas 75201 cc: Nicholas S. Reynolds, Esq.

Mr. Richard L. Fouke Debevoise-& Liberman Citizens for Fair Utility Regulation 1200 Seventeenth Street 1668-B Carter Drive Washington, D. C.

20036 Arlington, Texas 76010 Spencer C. Relyea, Esq.

Resident Inspector / Comanche Peak Worsham, Forsythe & Sampels Nuclear Power Station 2001 Bryan Tower c/o U. S. Nuclear Regulatory Commission Dallas, Texas 75201 P. O. Box 38 Glen Rose, Texas 76043 Mr. Homer C. Schmidt Manager - Nuclear Services Texas Utilities Services, Inc.

2001 Bryan Tower Dallas, Texas 75201 Mr. H. R. Rock Gibbs and Hill, Inc.

393 Seventh Avenue New York, New York 10001 Mr. A. T. Parker Westinghouse Electric Corporation P. O. Box 355 Pittsburgh, Pennsylvania 15230 David J. Preister Assistant Attorney General Environmental Protection Division P. O. Box 12548, Capitol Station Austin, Texas 78711 Mrs..Juanita Ellis, President Citizens Association for Sound Energy 1426 South Polk Dallas, Texas 75224 Geoffrey M. Gay, Esq.

West Texas Legal Services 406 W. T. Waggoner Building

..l' 810 Houston Street l<

Fort Worth, Texas 76102 I

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i ENCLOSURE REQUEST FOR ADDITIONAL INFORMATION CDMANCHE PEAK STEAM ELECTRIC STATION, UNITS 1 & 2 DOCKET NOS: 50-445 AND 50 446 S

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212.0 Reactor Systems Branch 212.85 The dis:ussion in Section 3.5.L.2.1 lists MSSS component (3. 5.1. 2) categories which are conside ed to have the potential for Missile Generation inside the reactor containment. A listing of specific valves t. hat have been considered under item b, "Certain Yalves" snould be provided.

212.86 Discuss the justification farr limiting postulated valve

( 3. 5.1. 2) failures to only those valves in the Westinghouse scope of supply or provide data to stuow that the valves considered represent a " worst case."

i 212.87 Discuss the bases for not mest_lating the generation of (3.5.1.2) secondary missiles by trapingemett of primary missiles as requested in Q212.10. If an es:eption is being requested, provide the bases and calcalations used to verify your position.

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212.88 It is stated that all isolation valves in the RCS have stens (3.5.1.2) with a backseat, thereby,eli=insting the possibility of eje: ting valve stens. It is further stated that the analysis shows the backseat er tne upse: end cannst penetrate the bonnet. Provide the concitions assumed in the analysis of this situation, and the results obtained leading to the stated conclusion. If tae study is referenceable, the reference should be pftvided.

212.89 Sergion 10.3.1 (FSAR page 10.3-3) discusses a pressure drop (5.2.2) in the main steam piping c' es: oximately 22 psi.

Subsection 10.3.2.1 (FS*.i page 10.3-5) discussing safety l

valves, addresses the highest safet-, valve setting which is based on 105% of the lowest valve set pres'sure minus 10 psi piping pressure loss. Ad.--ess the discrepancy between the two values for steam line piping pressure drop.

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Section 5.2.2.11.2 in order to assess compliance with the SRP and Branch Technical Fosition RS8 5-2 (Low Temperature Overpressure Protection).

I 212.91 Clarify the apparent discrepancy in the response to Q212.79.

Reference is made to the p-tss:rizer safety valve relieving capacity as 420,000 lb/hr and also as 210,000 lb/hr. It is assumed that the first reference (420,000 lb/hr) corresponds to a pressurizer relief valve rather than a safety valve as stated in the response.

212.92 The response to Q212.16, I:em (2) does not provide the (5.2.2) analyses or results required b; the staff to demonstrate that the system will provide tr.e required pressure relief capacity. Information nrast be provided to verify that all overpressurization events have seen considered and provide a basis for the criteria used to establish the worst case event. RS35-2 requires that pstential events may not be eldmi-eed from consideration in overpressure crotection design by imoosition of technical specifications or s.'

administrative. controls.

In reference to Item (6), justification must be provided for the exception taken to R58 5-2, that design of the overpressurization protection system to function during an OBE is not a credible desir, basis. Provi.de results of the evaluation referred to in R212.15, Item (5) for st ff.

evaluation of the exce; tion taken.

i 212.93 Provide indication as to when the evaluation results (5.2.2) referenced in R212.37, for it-iR piping overpressure protect 1on.will be provided for review.

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J 212.94 Provide a discussion to verify that total leakage to the (5.2.5) primary reactor containment from unidentified sources can be cellected and the flow rate monitored within the required accuracy of one gpm or bettar. The description of the primary monitors included under Section 5.2.5.2.2 of the FSAR does not provide sufficient information to conclude that the criteria for total unidentified leakage have been

' met.

212.95 Explain or resolve the discrepancy in functions of the (5.2.5) containment sump flow monitering systen and its ability to detect a one-gpm leak in ene hour. The response to Q212.18 indicates that a 4 ingh. change in stmip level corresponds to 60 gallons of fluid. FSAF. Section 5.2.5.3 also indicates that a 4-inch stmis level change in one hour co-responds to a 1 gpm leak. The response t: C212.6, however (discussing leakage collected in the sis::o), states that asu'sning a design basis leak of 50 g:m, tne su.; level will rise at a rate of 5 inches per minuce.

Provide assurances that leakage flow paths from the leakage sources to the detection sumps will be free of blockage and will not delay leak detection.

212.96 Discuss the accuracy and ser.s'tivity c' the air particulate (5.2.5) monitor for the postula:ec case where baseline leakage into the containment is high (:p er threshcid limit - within specifications). Verify that the acceptance c-iteria for sensitivity ar.d response time will still be met. i l

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212.97 Section 5.2.5.3 Subparagra:h (1) gives the threshold limit l

(5.2.5) of the containment air parti:ulate monitor as 5 x

-11 @ 3 Explain this limit or correct to tne 10 appropriate value.

i'i 212.98 Section 5.2.5.2 discusses leakage from the Reactor Head (5.2.5)

Flange Leakoff Systen and the Pressurizer safety and relief valves. It is stated that leakage is detected by surface mounted temperature detectors. Provide information to explain how leakage from these sources is monitored and how leak rates are obtained.

212.99 Provide a description of the p-ocedures used to convert each (5.2.5) leakage indication to a common leakage equivalent. Include _

in the discussion the interp e:ation o' signals from those leakage detectinn systems that provide inputs othe-than in the form of flow rates or level change measurements.

212.100 The motor operated valves in t..e R'-R miniflow bypass lines (5.4.7) are interlocked to flow transmitters in the pump discharge lines to open when the dis:harge flow is less than 500 som.

and close wht.n the flow ex:eeds 1000 g;m., Has this feature been used ia other Westinghcuse plants? What are the electrica's qualifications of trase interlocks? Provide the logic r.ircuitry for these inter 1ccks ar.d a discussion to i

provide assurance that any single fail:;re could not result in failure of both bypass valves, thereb/ causing damage to both RHR pumps.

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212.101 Section 5.4.7.2.6 of the F3*R sfcatas that the Auxiliary (5.4.7)

Feedwater System is capable of parforming the residual heat removal function for an exter.ded period of time following plant shutdown. Discuss taa f;nction of the Auxiliary Feedwater System, in this inade of cperation, and the duration of residual heat renoval provided.

Specifically, address the amount of primary water and backup water supplies. Address the safety grade and seismic qualifica-tion of these water sources.

212.102

Pressurizer safety and relief valve ficw rates for saturated (5.4.7) steam are given in Table.5.4-15.

Liquid flow rates for both pressurizer relief and pressurizer safety valves should be provided to kvaluate overpress;rintion protection during periods when the pressurizar is water solid.

21 103 Provide a discussion of the purpose and function of the

("O pressurizer relie# valve interlo:k listed en Table 5.4-10.

Is a dual setpoint type logic used to :rovide water solid overpressurization protection? Provide assurance that in the event of a single failure in the interlock system, the overpressure protecticn systan w:uld :: be defeated.

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.a 212.104 In addition to the response provided to Q212.35, provide (5.4.7) information to indicate if the air operated RHR heat exchanger outlet and bypass valves are equipped with air accumulators.. If so, can these valves be maintained in the desired control position for a period of time necessary to limit the rate of cooldown such that technical specifications are not violated? Provide an estimate of the time limit that the applicabla valves could be maintained in the desired control position, give,n that nonsafety grade instraent air supply has been lost. Provide justification for not including the air operated bypass and CCW inlet valves in the FMEA provided as Table 9.3-3.

212.105 Provide additi7nal infoma: ion to substantiate and quantify (6.3) the statement made in Sections 6.3.1 and 6.3.2.2.12, that spurious movement of a motor coerated valve due to an electrical f ault coincident with a LJCA, has been analyzed and found to be a very low proodility event. What bases were assumed for tne analysis and what results were obtained to arrive at the conclusici stated? What other component failure probabilities were comoared with the failure probability of the spurious coYeGent event to justify classification as a "very low" proodility event?

212.106 Provide the missing information conce-ning accumulator (6.3)

I borated water volne and nitrogen cover-pressure in Section 16 Technical Speci'i:ations, part 3/4.5 and confirm that these values were used in the analyses.

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212.107 Section 6.3.2.2.9.3 in discussing ace:raf ator sving disc (6.3) check valves states that based on satisfact:ry past operating experience, chect vahe leakage has not been a problem. A subsequent sta.amert is made that the accumulators can accept sone inlaskage from the CS without affecting availability. Based an past operatin-data for identical type check valves - mat is the stxim::n a.4unt (voltme) of inleakap consfdered to be acceptable (not exceeding technical specification limits on' water volume, boron concentration and nitroget pressure), and still verify that availability and operability have not been adve-sely affected?

l Provide the maximum tolerable intersystem leakaoe for all systems inter-

' facing with the RCS (e.g. RHEs, Acetsnulators, etc.). Also provide the means of detection and the minimum detectable amount of intersysten leakage.

212.108 The minimum flow bypass lines fras each safety injection (SI)

(6.3) pump fem a single line returning bypass ficw :: tne RWST.

This line contains a single : motor operated valvs 1-8313.

Discuss the consequences o' ::lesure of valve 1-8313 with the SI pumps operating and nomai discharge flow paths unavailable. Deconstrate t.at ::::plicance to BIP-EICSB-18 has been met and that no single failure 'can result in loss or degradation of both SI pc es.

212.109 a.

Justify r at including the following manually operated valves in the list of those valves the malposition of which could degrade ECCS parfomance:

ISI-047 ISI-048, 8485.(A and B), 8483 (A and 8),

8387 (A and 8).

b.

Identify any single valve manual or motor operated, the mali position of which could degrade the ECCS perfomance to less than the minimum assumed in the safety analysis.

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Provide additional infomation to permit staff evaluation of your exception to canpliance with Regulatory Guide 1.79, Discuss the containment sump design provisio.ns which preclude formation of vortices. If an exceptio-is claimed in lieu of full scale testing to verify the sums design, details of the test progrsn must be provided.

.nclude information of the model size, scaling fact:rs :tilized, basis and adequancy of the sizing criteria, comsarison of model parameters with post LOCA conditions, consideration of anticipated flow conditions and screen blockage.

212.111 Section 6.3.2.2.3 t'ates that if the Scron Injection Surge (6.3)

Tank innersion hea ars are inoperable, "sufficielt design capabilities" are available to prevent precipitation of the 12 weight percent horic acid within the surge tank.

Describe the capabilities referred to and the resultant solution temperatu e fer this backup mode of cp". ration.

212.112 Provide a discussion of the criteria, suppsrting analyses, (6.3) sequence of operation and operator action to reduce boiloff i

and prevent horen precipitation in the reactor vessel as discussed in Section 6.3.2.5.4.

The discussion should include your conformance to the staff position concerning baron flushing as follows:

(1) The baron flushing function shall not be vulnerable to a single active or limited passive failure (i.e.,

leakage of seals). Specifically, the limiting single active failure should be considered d:: ring the e

short-term period of cooling. During the long-term period of cooling, the. limiting single actlys failure should be considered and so should a limiting passive

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(2) The inadvertent operation of any motor-ope atad velve (open or closed) shall not compromise the boron flushing ' unction nor shall it jeoparcize the ability to remove deny heat from the primary systen.

(3) All components of the system which are witnin containment shall be designed to Seist:fc Category I requirements and classified Quality Group S.

(4) The primary mode for maintaining acceptabla levels of boron in the vessel should be established. Should a single failure disable the primary mode, certain manual actions outside the control room may be allowed, depending on the nature of the action and the time available to establish the backup mode.

(5) The average boric acid concentration in any region of the reactor vessel should not exceed a level of four weight percer.t belcw the solubility lictits at the temperature of the solution.

(6) During the post-LOCA long-tenn cooling, the ECC system

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normally operates in two modes: the initial cold leg

. injection mod's, followed by the flushin9 mode. The actual operating time in the cold leg injection mode will depend on plant design and steri binding considerations, but in general, the switchover to the flushing mode should be made between 12 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after LOCA.

(7) The minimum ECS flow rate delivered to the vessel during the flushina niode shall be sufficient to accomodate the boiloff due to fission product decay heat and possible liquid entrainment in the stema discharged to the containment and st91 nrovide sufficient. liquid flow.through the n re to prevent.

further increases in boric acid concentration.

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(8) All flushing modes shall maintain testability 5

comparable to other ECCS modes of operation (HPI-short term, 1,7I-short term, etc.). The current criteria for levels of ECCS testability shall ce used as guidelines (i.e., Regulatory Guides 1.66, 1.79, EDC 37).

i 212.113 Section 6. 3.5.4.1 states that the RWST low-low leve! alarm (6.3) alerts the operator to realign the ECCS fran injection to recirculation mode following an accident. Section 6.3.2.8 states that-the time delay following a g-9, RWST signal in which the operator's failure to act will have no adverse effects. is nine minutes. With a time delay greater than nine minutes it is ass =ed that hign head safety ii7.f9ction and chargir.g pu=ps coulo be lost. Discuss the potential consequences of this time delay and con'pliance with SRP 6.3,Section III, Item 19, which states that where manual action is used, a sufficient time (greater than 20 minutes) be available for the operator to respond.

Also, assuming that all systems disecssed in Section 6.3.2.8 i

are operating, what is the total delay time between the RWST j.,o,-level signal and the M-Q level signal?

212.114 (15.3.2)

Section 15.0.1.2, in discussing Category II events, states that "by definition, these faults do not propagate to cause a more se-icus f ault, i.e.," Condition III or,.IV events."

Section 15.2.6 defines loss of nonemergency AC power as a Condition II event. Section 15.3.2, however, lists the loss of electrical suoplies (nonemergency AC power) as an initiating event f:r a complete loss of forced reactor coolant flow transient which is classified as a Condition III event. This discrepancy should be explained or resolved.

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2 212.115 The informatica requested to comple int the eval::ations for (15.0) each Chapter 15 event has not Deen,' evided in its entirety. 5.::cary Elec< Diagrams is described ir. Q212.57

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have not been included for the following Chapter 15 events discussed in the FSAR:

1 (15.1.2) Feer. vater system malfunctions tnat result in increase in feedwater flow.

2 (15.1.3) Excessive increase in seconda y steam flow 3

(15.1.5) Steso system piping failure, Offsite por available, offsite power not available 4

(15.2.3) Turbine trip 5

(15.2.5) Loss of Condenser Vacuum (acceptable if included in 15.2.3) 6 (15.3.3) Rear or coolant pump shaft seizure 7

(15.3.4) Reactor coolant pump shaft breax 8

(15.5.2) Chemical volume and control systec malfunction that f..c tases reactor coolant invente y 1

9 (15.5.~.) Inadvertent opening of a press:r-izer safety or relief valve f10 (15.5.2) 3reak in an instrument line or cther lines i

from reacter coolant pressure boundary that penetrates contairnent Diagrams ^similar to those described..in Q212.67,:and those provided in response to QO32.1~should~be provided for the above listed etents.

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l 212.116 The folicwing pertain to Chapter 15 Event Block Diagram (15,0 Sequences found in the response to Q032.1:

1.

Analyses having a reactor trip sequenet assume" that the control rod insertion is single failure proof, i.e.,

the single rod of greatest worth is assmed to stick out. The diagrams should reflect this by adding the single failure symbol below the rod insertion symbol.

2.

The block diagram sequence for the Dropped Rod Cluster Cont ol Assembly,(QO32.1-10) includes a reactor trip frm. full power. Normally, the turbine is tripped auttmatically on reactor trip, so either the. turbine bypass system, or power operated relie' valves, or safecy relief valves must be actuated to hando steam fra tne steam generators. Since only safety grade systa=3 tre assumed to operate during the transient, the sa'e:y relief valves would be asstc ed to operate.

Tney sr.o ld thus be shown in the diagrrn. The turbine bypass system and condenser have the cacability of handiirg 40% of full load main steam flow. The power operated relief valves are specified te pass a minima of 10% of design flow. Ther,efore, it would appear that even if these systems were operational, actuation of the safety valves would still be required on a trip from ft:11 power.

3.

Figure Q032.1-8, " Loss of Forced Reactor Coolant Flow."

For the partial loss of flow and single pump a.

laes rotor Item 2 applies.

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For total loss of flow, since offsite power is assuned to be lost, the main feedwater pumps would be lost and the auxiliary feedwater would be required. A sequence for auxiliary feedwater should therefore be. shown on the sequence diagra.

Reference should be made to the sequence diagran c.

for station blackout, since the total loss of flow (caused by station blackout) should be identical.

4.

Figure QC32.11-12, the analysis of this event has assuned caxim:n permissible power with one loop out of service. Tnis leads to the potential requirement for the secor.dary safety relief valves. Refer to Iten 2

'or discussion.

5.

Figure Q032.1-3, "Depressurization of Main Steam Syste:n. "

Since the mainsteam lines will be isolated during a.

this trardient, the secondary safety relief valves will protably be required for heat removal from the secondary systen.

If this could occur, a sequence for secondary relief valve actuation should be added to the diagram.

b.

. Main steam and main feedwater isolation sequences shsQld reflect any required redundancy with ap:ropriate single failure symbols.

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Figure C032.1-11 " Single Rod Cluster Control Assenbly Witsdrawal at Full Power" See Item 2 for discussion of the possible need for secondary safety valve actuation on reactor trip from full power.

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Figure Q332.1-7 " Major Rupture of a Main Feedwater Line." See ccanent as.Itan 6.

8.

Figure QO32.1-14 ' Rupture of a Control Rod Drive Mechanisu Housing." Same coment as Ita 5.

9.

The Chapter 15 cvant diagrams that have assmed turbine trip or reactor trip in the analyses should include a sequence for turbine trip, with a;propriate single ~ ~~ ~~

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f ailure designations.

212.117 Section 15.0.2 discusses a comprehensive control systen (15.0) setpoint study that will be pedonned in order to simulate otrfen.uce o# tne reactor control and prottetion systen.

Pmvide a su:: nary and results of this study or a date when this infc mation will be available for staff review to assess a;olication and impact on Comanche Peak reactor control ed protection systems.

212.118 Provide as part of Table 15.0-3, or' where upropriate, the

. 0. M i initial press:frizer water volume assmed in applicable Chapter 15 accider.t analysas. Include a discussion to indicate the, degree of conservatism provided by the pressurizer valme assmed.

212.119 Provide or reference analyses for the transient events which- - -~

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show that the acceptance criteria are met for initial

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operation with less than four leops.

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i 212.120 The case discussed in Section 15.3.2.2 for the loss of four (15.3.1) pumps with fo::r loops in operation, states that DIGR is always greater than 1.30. Referring to Figure 15.312, it appears from the plot of DNBR versus time, that DNSR is marginally close to 1.30.

Provide additional information for this event including an estimation of analysis error bands to substantiate your conclusion that CNBR for this event is always greater than 1.30.

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I' 212.121 Provide performance curves for the primary water makeup (15.4.6) pumps to verify that dilution flow rates asstaned in the analyses for cold shutdown, hot standby and startup conditions are conservative.

212.122 Provide a discussion to verify that the charging pump flow (15.4.6) rate assumed for the dilution. rate (200 gpm) during full power operation, is conservative. The analysis for this condition asszes that all charging pt nps are in operation.

212.123 The discussion in Section 15.5.1.1, " Inadvertent. Operation (15. 5.1) of the Emergency Core Cooling System During Power Operation," indicates that several decisions and judgements must be made by the operator. - The 1spe-ator must detennine 4

if the spuricus signal was transient or steady state, determine if the SI signal should be blocked, did the trip occur or not, etc. What are the possible consequences of operator erre - making an incorrect judgenent? Following a spurious sigt.al, how long must the o.vtrator wait until the SIS can be resa:7 Assisning that a loss of offsite power occurs after reset of the SIS, will all essential loads be picked uo automatically in the event of the subsequent LOCA? If not, what procedures must the ope-ator follow to ensure. that essential equipment is-sequentially. loaded >onto the energency generato-s?

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212.124 Provide additional information to verify that the stated

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.5.1) accuracy o' the pressurizer water level indicators (?,,25% of span, Se: tion 7.5.1) is sufficient to enable the operator to perfor:s all required manual safety functior.s such as maintaining charging flow control within specified limits.

212.125 Provide a discussion of the long term effects following a

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steam line break event. A complete assessment of the operator's role in preventing pressure-temperature limits from being ex: ended should be provided.

212.126 Discuss the bases for the " conservative" and " realistic" (15.1.5) values used in the analysis for long term steam release from a defective steam gene-ator (Table 15.1-3, Sheet 3 of 4).

212.127 Provide references to, or sununaries of the postulated (15.1.5) transients referred to as the bases for establishing that capacities of the steam generator and pressurizer safety valves for Casanche peak are greater than discharge rates calculated in Chapter 15 analyses.

212.128 Provide a referen:e to the feedwater line break case analyses (15.2.8) which detemined the most limiting feedwater line rupture transient.

212.129 One of the merger:cy operating procedures identif.ied j

(15.2.8) following a secondary steam line rupture (with offsite power available), is to turn off all reactor coolant pumps.

Provide justification for this action, particularly in light of the Technical Specification 3/4.4 requirement that one reactor coolant loop is nece.sary to provide sufficient heat removal capability while in Hot Standby, or placing one RHR loop in the shutdown cooling mode if repairs and/or corrective a: tion cannot be made within the. allowable out-of-service tice.'

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L 212.130.

SRP, Sections 15.3.3, 15.3.4 classify the Reactor Coolant j

(15.3.4)

Punp Rotor Seizure and Reactor Coolant Pump Shaft Break events as infre:;uent transients. Provide justification for j

the FSAR classification of these events as Limiting Fault Events. Verify that the transient results meet the acceptance criteria fc an Infrequent Event as defined by tne SR?.

212.131 The discussten in Sections 15.'3.3.2 and 15.3.3.3 does not (15.3.3) provide clarifica-icn, based on the fuel da:iage model, whetner fuel fail::re (rod perforation) is assumed to occur.

If fuel f ailure d:es' cecur under some conditions, and does noc cc:ur for c:her conditions assumed in the analyses, prt.,Jide justift:ation and bases, since DNS is assumed to occur at the initiation of the transient.

212.132 Provide justification for the statement ::ade in FSAR (15.6)

Section 15.6, page 15.5-1, Event 2, that a breac in an instrument line E cther lines frau the Ratetor Ccolant Pressure Scundary that per.ecrate contait=tr.t is not applicable to CPSES. In discussien of this eve-t provided in FSAR Section 15.6.2, other lines are identified and iscussed - that penetrate containment.

212.133 Discuss the transient resulting from a break of an ECCS (15.6.5) injection line.

In particular, describe tt:e fisw splitting which will occur in the event of a single failu e, and verify that the amount of flow actually reaching the core is consistent with the assumptigns used in the analysis.

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212.34 Table 15.6-6 (Large Break-Analysis Input ar.d Results) lists (15.6.5) three safety injection pumps operating. Tte system design as discussed in Section 5.3 and shown on Figu e 5.3-1, Sheet 3, shows two safety injection pumps. Explain this discrepancy and indicate tne numbe of safety injection peps conside-ed in the large break analysis.

212.135 Provide a specific reference including d-aming title, (7.4.1. 3)

, neber, sheet, revistor..?.nd date for tre het shutdown panel layout drawing identifit.d in.25AR 3ectier 7.4.1.3.

212.136 Your response to question Q212-78 was identified to be (15.4.6) provided "later." Provide response to this question or indicate wher. this information will be proviced for staff review.

. f 311.0 Site Analysis Branch i

311.01 Section 2.1.2.1.1 states that you have acquired and will maintain g

surface ownership of all but a small portion of the land within 2.1.2.1 the Exclusion Area with a reference to Figure 2.1-2a.

Please identify the land within the Exclusion Area which is not owned.

This section further states that you will acquire the remainder of the surface rights prior to fuel loading. Please provide your schedule for acquisition of the remaining surface rights, or other suitable arrangements for demonstrating authority to determine all activities within the exclusion area. Without a showing of such authority, the staff, as required by 10 CFR Part 100, will be unable to reach a favorable conclusion on this matter.

311.02 You have indicated that there are mineral rights within the 2.1 exclusion area that are presently owned by other parties and that are intended to remain so during plant operation.

You have also stated that a gas well accident postulated to occur beyond 2250 feet from any safety-related plant structure will not affect the safe operation of the CPSES (in this regard, please see-our related question Q311.03), and have indicated, therefore, that mineral exploration within the exclusion area, but beyond this distance will not represent a hazard. Since 10 CFR Part 100.3a permits plant unrelated activities, under appropriate limitations, provided that no significant hazard to the public health and. safety will result, we agree that mineral exploration beyond a certain distance (which, please note, is still under review and evaluation), but within the exclusion area will be acceptable. However, you should explicitly indicate if you have not already done so, by accending the FSAR as appropriate, the following:

(a)

Indicate how you will be made aware of mineral explora-tion activities in this area, including numbers of personnel, locations, etc.

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(b)

Indicate your authority to remove perso.nnel and property and in the event of emergency, and (c)

Provide an analysis and results of the radiological conse-quences to mineral exploration personnel who may be in the exclusion area from'the' limiting design basis accident, and provide assurance that these doses will not exceed the guideline: values.given in;10.CFR:Part.100. -

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- 311.03' Your response to questions 312.4. 312,14, and 372.19 has not 2.1 provided sufficient information for us to reach a conclusion.

Please provide a detailed analysis which specifically discusses potential accidents at the closest point where mineral exploration may be permitted, including effects of fire, spillage and a gas well blow out. Your analysis should specifically discuss and consider the following:

The effects of fire both with regard to heat flux upon

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(a) the plant as well as effects of dense smoke upon control recm habitability.

(b)-

The effects of any oil spillage, assuming oil is extracted, including consequences of oil runoff and features to mitigate or preclude this.

(c)

The effect of a gas well blow out which conserva-tively considers the release and delayed ignition of any non-buoyout components, such as ethane and propane, found in natural gas.

(d)

The effect of detonation of explosives which may be used both in mineral extraction operations as well as extin-quishing of fires.

In this regard, your response to items 3 and 4 of Q312.14 is inadequate.

Please provide an indication of the maximum quantity and type of explosives that might be used in connection with the activities identified above.

(e)

Indicate the overpressure, in psi,.that the safety-related structures are designed to withstand.

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(f)

Describe in detail the atmospheric dispersion models used including assumptions.

Please state all other assumptions used.

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3-311.04 Please provide a revised Figure 2.1-2c which identifies the 2.1 10 CFR Part 100 exclusion area boundary explicitly on Figure 2.1-2c and identify (on this figure) the area where no ingress will be allowed for purposes of mi..aral exploration.

Texas Utilities Services Inc. letter of May 23, 1980, Rest to 4

Schwencer, Log # TAX-3143, File 10010 transmitted geologic information compiled by H.'J. Gray and Associates, Inc.

Included with this information was a map which apparently

~_ identified mineral right owners. The ownership indicated on this map is not consistent with Figure 2.1-2c.

Please explain.

311.05 Provide the' size, location, orientation, and height above grade 2.1 or burial depth of all fuel oil, gasoline, toxic chemicals, and high energy lines onsite or within one mile of the site bnundary.

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371.0 Hydrologic and Geotechnical Engineering Branch 371.16 The summer of 1980 produced a long period of parsistent hioh temperatures

. greater than 100'F. What effect will -these data have on your ultimate heat sink performance analysis and equipment design.

371.17 In section 2.3.1.2.2 of the FSAR, you refer to -a Probable Maximum Hurricane

-(PMH)with~awindspeedof81 miles.perhourmph.

In section 2.4.5.1 you used a probable maximum sustained over-land wind of 81 mph. You further state that the return period of this wind is about 200 years.

In section 2.4.8.2.2 you refer to a Probable Aximum Wind of 87 mph which has a 200 year frequency. Provide clarification of the terms Probable Maximum Hurricane Wind and Probable Maximum Over-Land Wind. Also, was 81 mph or was 87 mph'used in your analyses.

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371. 18 Our analysis of the performance of.the stilling b'asin on the Squaw Creek Dam Service Spillway indicates that the height and length of a hydraulic jump,, caused by a discharge of 22,500 cfs, could exceed the design capacity of the stilling basin. -This could possibly lead to failure of the spillway which could affect the stability of the toe of Squaw Creek Dam., Provide supporting documentation to.;how how you determined a stilling basin length of 143 feet and a height of 35.5 feet. As a minimum provide all variables used in the momentum equation.

Include depths, velocities and Froude numbers.

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