ML051050177

E-mail from P. Krohn, Riii, to H. Chernoff, NRR, Pb 1MS-228 Leaking Vlv. Background Material & Attachments

ML051050177
Person / Time
Site:	Point Beach
Issue date:	06/07/2004
From:	Paul Krohn Division of Nuclear Materials Safety III
To:	Chernoff H Office of Nuclear Reactor Regulation
References
FOIA/PA-2004-0282
Download: ML051050177 (27)

Text

Harold Chernoff - PB 1 MS-228 Leaking Vlv. Background material.

Page 1 From:

To:

Date:

Subject:

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.i 14.2.4 Steam Generator Tube Rupture General A complete single tube break adjacent to the tube sheet in a steam generator is examined for two assumed situations. Since the reactor coolant pressure is greater than the steam generator shell side pressure, the contaminated reactor coolant discharges into the secondary system.

The activity release is limited by operator action to terminate the primary to secondary fluid leakage and the releases from the affected steam generator to the atmosphere. The analysis of the offsite consequences assumes that break flow termination occurs thirty minutes after the postulated tube rupture accident.-An assessment performed by Westinghouse concludes that the break flow termination could be increased from thirty minutes to approximately 44 minutes without exceeding the integrated break flow, ruptured steam generator atmospheric releases and radiological consequences. The Westinghouse assessment and conclusions are based on the assumption that the ruptured steam generator does not overfill, such that liquid does not enter the steamline piping (Ref. 8).

Method of Analysis A detailed time sequence of events is presented from occurrence of the assumed steam generator tube rupture until the primary to secondary break flow and release from the affected steam generator to the atmosphere have been terminated. Resultant radionuclide releases to atmosphere have been evaluated assuming that off-site power is lost.

The potential for an increased radioactive release to the environment due to steam generator tube bundle uncovery has been evaluated (Ref. 3). Uncovery does not significantly increase the radiological consequences associated with the SGTR accident. The probability of a significant release due to non-SGTR events, including the effects of tube uncovery, is sufficiently low to exclude such events from consideration. The NRC agrees with the position that the effects of partial steam generator tube bundle uncovery on the iodine release for SGTR and non-SGTR events is negligible (Ref. 4).

-Analvsis Assuming Minimum Auxiliary Feedwater and Off-Site Power are Available The sequence of events following tubehiupture is as follows:

1.

Primary leakage takes place initially at a high rate (-87 lbm/sec) but rapidly drops to a lower leak-ageirate (-55 Ibin/sec).

2.

Within seconds, air'ejedtor discharge of radionuclides may'be alarmed by the auxiliary building-vent stack monitor, thus warning the operator.

3.

Pressurizer water level will continue to decrease for up to approximately five minutes before an automatic low' pressure trip will occur. Normal core protection trips are available to prevent core damage during this time and may cause an earlier trip.

4.

Safety injection is automatically actuated on low pressurizer pressure and the reactor coolant system is borated by the high head safety injection pumps.

5.

Isolation of the affected steam generator can be achieved within about ten minutes by:

a.

Identifying the affected steam generator by early observation of rising liquid level, observing steam line radiation monitors, or analysis of a steam generator liquid sample.

b.

Closing the steam line isolation valve connected to the affected steam generator.

c.

Securing the auxiliary feedwater flow to that steam generator.

6.

Other procedures to terminate primary-to-secondary leak flow through the ruptured tube include:

a.

Operator-controlled steam dumping to the condenser in order to; (l).reduce'the reactor coolant temperature; (2) maintain primary coolant subcooling; (3) to minimize steam discharge from the affected steam generator.

b.

Operator-controlled RCS depressurization to restore reactor coolant inventory.

c.

Termination of safety injection'in order to terminate primary system leakage to the affected steam generator.

7.

Should the affected steam generator main steam isolation 'valve not close, the main steamline dump valves would be closed and atmospheric relief from the unaffected steam generator would be used for steam dumping (plant cooldown). (This case is described below.)

8.

The unit has been cooled down and depressurized to an equilibrium condition where no further reactor coolant is discharged to the affected steam generator or steam released from the affected steam generator to the atmosphere.

Analysis Assuming Availability of Minimum Auxiliary FeedwaterWithout Off-Site Power For the purpose of this analysis, it is assumed that when reactor trip occurs station -normal power is lost. The reactorcoolant' pu'mps' will then coast down and the condenser circulating water pumps will stop. On-site emergency power is available from the diesel generators to supply the necessary engineered safeguards equipment.

Core decay heat is then removed by natural circulation of reactor coolant to the steam generators. The atmospheric steam reliefvalves will open automatically to relieve'high pressure in the steam generators. Ste'am dump to the condenser-is isolated-when condenser vacuum is lost. During this time, secondary safety valves may also lift.

Main steam safety valves open to restore primary system temperature to the hot shutdown value. They are designed to blowdown to 12.6% below the setpoint pressure to remove decay heat while maintaining the hot shutdown system pressure (Reference 9). With no operator action, the main steam safety valves would maintain the primary system temperature between approximately 540 and 5571F.

The safety injection system borates the reactor coolant system within several minutes and will eventually refill the reactor coolant system and pressurize it to a pressure at which the injection flow is balanced by discharge through the broken tube. Initially, the water level in the unaffected steam generator will decrease because the emergency feedwater will not match the steam relief needed to reduce the reactor coolant system to no-load temperature. When the steam dump is reduced to balance decay heat, the emergency feedwater supply exceeds decay heat requirements and the liquid level in the unaffected steam generator will increase.

Because of the discharge from the reactor coolant system, the rate of increase in liquid level is greatest in the faulty steam generator.

Up to this point, automatic actions will ensure safe shutdown of theTeactor. Automatic actuation of safety injection will ensure that the core will not be damaged, and thus limit radioactivity releases to the level of the concentrations in the reactor coolant.

Within 30 minutes, the safety injection system will have refilled the reactor coolant system and the operator will have time to determine which steam generator is faulty by observing steam generator levels, steam line'radiation monitor, or analysis of a steam generator liquid sample. -After the initial transient, the operator would isolate the affected steam generator, and perform a limited cooldown to assure-subccoling margin. The safety'injection system will maintain reactor coolant system pressure and pressurizer level, compensating for losses due to discharge in reaching pressure equilibrium between the reactor coolant system and the now isolated faulty steam generator and for contraction losses during the remainder of cooldown.

After cooldown, RCS depressurization would be performed to restore reactor coolant inventory, and subsequently the safety injection flow would be terminated to stop the primary-to-secondary break flow.

After the primary-to-secondary break flow has been terminated, the RCS would be cooled down to cold shutdown conditions. The cooldown is initiated by manually controlling the steam relief on the unaffected steam generator.'The relief valve and auxiliary feedwater pump capacities are adequate-to cool down at O0OFlhour. At this rate, approximately 4.hours are required to cool:down and depressurize the system to 350 psia, at which time the residual heat l removal 6loop can be used to complete cooldown. During the cooldown, no further activity is I discharged from the.isolated stea.

genator.

T Radioloeical Consequences of a Steam Generator Tube Rupture Accident This section presents an evaluation of the offsite consequences of a steam generator tube rupture accident. The specific analyses conducted for the PBNP offsite consequences were generally accepted by NRC (Reference 7) and further modified by Reference 10, which corrects non-conservative input parameters used to calculate the accident-initiated iodine spike. However, the analyses of control room habitability were subsequently identified for further review. Therefore, a quantifiable description of the control room habitability assessment are not provided herein; however, the general results are provided.

Assumptions: The following assumptions were used in the analysis of-the offsite conseqtiunces:

I.

Both pre-accident and accident initiated iodine spikes are analyzed. For the pre-accidentiodine spike, it is assumed that a reactor transient has occurred prior to the steam generator tube rupture.and has raised the RCS iodine concentration to 50 gCi/gm of dose equivalent (DE) I-131. For the accident initiated iodine spike, the reactor trip associated with the steam generator tube rupture creates aniodine spike in the RCS which increases the iodine release rate from the fuel to the RCS to-a value 500 times greater than the release rate corresponding to the maximum equilibrium RCS Technical Specification concentration of 0.8 gCi/gm of DE I-131. The duration of the accident initiated iodine spike is '1.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. (Reference 5)

2.

The noble gas activity concentration in the RCS at the time the accident occurs is based on a fuel defect of 1.0%. This is approximately equal to the Technical Specification value of 100/E-bar pCi/gm for gross radioactivity.

l 3.

The iodine activity concentration of the secondary coolant at the time the steam generatorttube rupture occurs is assumed to be equal to the Technical Specification limit of 1.0 pCi/gm of 1-131.

4.

The amount of primary to secondary steam generator tube'leakage in the intact steam generator is assumed to be equal to'the Technical Specification limit for'a single steam

-generator of 500 gallons/day.

5.

No credit for iodine removal is taken for any steam released to the condenser prior to reactor trip and concurrent loss of offsite power.

6.

An iodine'partition factor in the steam generators is used as follows: 0.01 (curies Iodine / grm steam --'curies Iodine I gin water)

7.

All noble gas activity carried over to the secondary side is assumed to be immediately released to the outside atmosphere.

8.

Thirty minutes after the postulated tube rupture accident, the pressure between the ruptured steam generator and the primary system is equalized. Approximately 123,600 lbs. of reactor coolant is discharged to the secondary side of the ruptured steam generator. Also, approximately 74,000 lbs. of steam is released to the atmosphere via the ruptured steam generator during the time interval.

9.

Auxiliary feedwater is available during the accident.

10.

Eight hours after the accident the residual heat removal system is assumed to be placed in service and there are no further steam releases'to the atmosphere -from the l

secondary system. (Note that this is an analysis assumption in the approved j

radiological -analysis that terminates steam releases. The RHR safety-related and J augmented quality functions are described iniFSAR Section 9.2.)

11.

Breathing rate used to calculate the'thyroid dose for the accident is'3.47xlO4 m3/sec.

Prior to the steam generator tube rupture (SGTR) accident, it is assumed that the plant has been operating with simultaneous fuel defects and steam generator tube leakage for a period of time sufficient to establish equilibrium levels of radioactivity in primary and secondary coolant. The offsite and control room doses following a SGTR are analyzed considering both pre-accident and accident initiated iodine spikes. For the preaccident iodine spike, it is assumed that'a reactor transient has occurred prior to SGTR and has raised 'the RCS iodine concentration to the allowed Technical Specification value of 50 p.Ci/g. For the accident-initiated iodine spike, the reactor trip associated with the SGTR creates an iodine spike in the RCS which increases the iodine release rate from the fuel to the RCS to a value of 500 times greater than the normal equilibrium rate corresponding to the initial RCS iodine activity. For both of these iodine spike cases, the SGTR radiological analysis includes three primary sources of activity: (1) initial secondaky side iodine activity, (2) RCS coolant activity released via primary to secondary steam generator tube leakage in the intact steam generator, and (3) RCS coolant activity'carried over from the primary coolant via the ruptured steam generator tube.

The model for the activity available for release to the atmosphere from the -ruptured and intact steam generators assumes that the release consists of the activity in the secondary coolant prior to the accident plus 'that activity 'leaking from the primary coolant thr'ough 'the SG tubes following the accident. The primary coolant activity 'after the accident is assumed to be composed of the pre-accident iodine spike activity or accident initiated iodine-spike activity, plus the noble gases released due to '1% fuel defects. The leakage of primary coolant to the secondary side of the SG is assumed to continue at its initial rate of 035 gpm in the intact SG

'for the duration of the accident. A coincident loss of offsite power is assumed resulting in the loss of the condensers and the release of activity'to the atmosphere through the main steam safety valves and the atmospheric 'steam relief valve from the intact steam generator. Eight hours after the accident, no 'further steam or activity is released to the environment.

A separate thermal hydraulic analysis was performed to determine the amount of reactor coolant transferred to the secondary side of the ruptured steam generator and the amount of steam released from the ruptured and intact steam generators to the atmosphere. This analysis was performed to support a power uprate program for Point Beach Units l & 2 and is used to conservatively bound the replacement steam generator program. A specific thermal and hydraulic analysis was performed for the replacement steam generator program. The values for primary to secondary'break flow and steam released to the atmosphere are bounded by those calculated at the uprated power conditions. Per'this analysis 'the break flow through the ruptured steam generator will deliver 123,600 ibm of reactor coolant to the secondary side of the steam generator. None of the break flow is assumed to flash in the steam generator resulting in a direct release to the enviroiiment. The primary to secondary break flow is assumed to persist until 30 minutes after the initiation of the SGTR, at which time it is assumed that the, operators have completed the actions necessary to terminate the break flow and the steam release from the ruptured steam generator.-The amount of steam released from the ruptured steam generator during the 30 minute time period is calculated to be 74,000 lbm.

A partition factor of 0.01, as defined in'SRP 15.6.3, is applied to this steam release. No credit is taken for additional partitioning in the condenser prior to reactor trip. Both the break flow and steam releases are averaged over the 30 minute time interval.

The Westinghouseeanalysis for SGTR is' comprised of 5 separate computer runs; a nominal RCS iodine activity case, a pre-accident iodine spike case, an accident initiated iodine spike case, an initial secondary coolant iodine case and a noble gas case. Each of the iodine cases model the releases to the environment from both the intact and ruptured steam generator using a partition factor of O.01 on the steam releases. For each of these cases, except the initial secondary coolant iodine case, a transfer is modeled from the RCS to the steam generators based on primary to secondary leakage to the intact SG and the breakflow through the ruptured SG.

The activities in the steam generators and those released to-the environment at the end of the 30 minute and 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time intervals were evaluated. After 30 minutes, no further activity release from the faulted steam generator was assumed. Primary to secondary leakage to the intact steam generator is terminated 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the accident. The reduction in the concentration of the ruptured steam generator between 30 minutes and 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is due to radioactive decay.

The analysis specifies a total release time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, for conservatism and to be more consistent with typical analysis values. The total steam releases from the intact and ruptured SGs are summarized below.

Rate of Steam Release Mass of Steam Released (gamin) flrml Ruptured Steam Generator 0-0.5hr 1.12E6 74,000 Intact Steam Generator 0 - 2 hr 6.28 E6 1.66 E6 2 - 8 hr 4.72 E5 3.74 E5 The noble gas case models a release directly from the RCS to the environment based on primary to secondary leakage to the intact SG and the breakflow'through the ruptured SG assuming an RCS coolant activity corresponding to a fuel defect level of I percent.

Two release paths are assumed for the accident. For the source-term in the RCS, releases are assumed to occur through the tubes in the steam generator with subsequent release out through the safety relief valves or the atmospheric'steam dump valve for both the intact and faulted steam generators. The release point for the safety relief valves or the atmospheric steam dump valve is assumed to be the vents associated with the valves. These valves exhaust to the environment through the top of the facade at an elevation of 170 feet. For both release points, atmospheric dispersion factors were calculated. The most limiting factor was then used for both release points 'to evaluate the dose consequences of the releases.

The thyroid dose conversion factors, breathing rates, and atmospheric dispersion factors used in the dose analysis are given in'Table 14.1.8-3. The assumed core and coolant activities are given in Table 14.1.8-4.

Acceptance Criteria The offsite dose limits for a SGTR accident with a pre-accident iodine spike are the guideline values of 10 CFR 100. These guideline'values are 300 rem thyroid and 25 rem whole body.

For a SGTR accident with an accident-initiated'iodine spike, the acceptance criterion is a "small fraction" of the 10 CER 100 guideline values; or 30 rem thyroid and 2.5 rem whole body. The criteria defined in the Standard Review Plan Section 6.4 are used for control room dose limits: 30 rem thyroid, 5 rem whole'body, and 30 rem beta skin. (Reference 6)

IVAg NUCLEAR REGULATORY COMMISSION WASHINGTON. D.C. 20555-OCOI February 22, 2002 Mr. Mark Reddemann Site Vice President Kewaunee and Point Beach Nuclear Plants Nuclear Management Company, LLC 6610 Nuclear Road Two Rivers, WI 54241

SUBJECT:

POINT BEACH NUCLEAR POWER PLANT, UNITS 1 AND 2-EMERGENCY RESPONSE CAPABILITY - CONFORMANCE TO REGULATORY GUIDE 1.97, REVISION 2.(TAC NOS. MB2782 AND MB2783)

Dear Mr. Reddemann:

By letter dated July 27, 2001, Nuclear Management Company, LLC (the licensee), requested approval of deviations and clarifications fromRegulatory Guide 1.97, "Instrurnentatlon for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," for the instrumentation that monitors containment Isolation valve position at the Point Beach Nuclear Plant, Units I and 2.

The U.S. Nuclear Regulatory Commissioh (NRC) staff had previously evaluated conformance to Regulatory Guide 1.97 at Point Beach, Units 1 and 2, and concluded that it was acceptable, as documented in safety evaluations date'd July 11, 1986, and September29, 1992.

The NRC staff has reviewed the additional information provided in your letter dated July 27, 2001. The NRC staff finds the proposed deviations from Regulatory Guide 1.97 acceptable.

The NRC staff, therefore, still finds that the Point Beach, Units 1 -and 2, design is acceptable with respect to conformance to Regulatory.Guide 1.97, RevisIon 2.

Enclosed is a copy of the NRC staffs supplemental safety evaluation summarizing the review of the licensee's July 27, 2001, submittal. This completes the NRC staff's review work for TAG Nos. MB2782 and MB2783.

If you have any questions regarding this matter, I may be reached at 301-415-1446.

5 erel on G. Lamb, Project Manager, Section 1 Project Directorate IlIl Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-266 and 50-301

Enclosure:

Safety Evaluation cc w/encl: See next page I

toNUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SECOND SUPPLEMENTAL SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION CONFORMANCE TO REGULATORY GUIDE 1.97 NUCLEAR MANAGEMENT COMPANY. LLC POINT BEACH NUCLEAR PLANT. UNITS 1 AND'2 DOCKET NOS. 50-266 AND 50-301

1.0 INTRODUCTION

The U.S. Nuclear Regulatory Commission (NRC) staff has completed Its review of the Nuclear Management Company's, LLC (the licensee's), conformance to Regulatory Gufde.(RG) 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,t. Revision 2, for the'Point Beach Nuclear Plant, Units 1 and 2, by providing the NRC staff's safety evaluation to the licensee on July' 11, 1986, and a supplemental safety evaluation'on September 29, 1992. The NRC staff found that the licensee's design was acceptable with respect to conformance to RG 1.97, Revision 2. By letter dated July 27,^2001, the licensee Identified ambiguities and inconsistencies in the documentation concerning containment Isolation valve position indication. The licensee has provided information to correct these ambiguities and inconsistencies and has requested that the NRC staff evaluate the issues conceriing' this instrumentation.

2.0 EVALUATION RG 1.97 recommends that Category 1 position indication be provided in the control room for each containment isolation valve (excluding check valves) to provide the operator with information concerning the accomplishment of isolation of the containment. RG 1.97 also recommends that the information provided by each Category 1 instrument be recorded.

The licensee 'deviates from a strict interpretation of'the Category I redundancy recommendation. Only active containmerit Isolation valves (automatic valves that receive a containment isolation signal) have RG 1.97 position indication in the control room. Since redundant containment isolation valves are provided for each penetration, redundant indication per valve is not intended by the RG.

Remote-manual containment isolation valves do not perform an active containment isolation function that requires closure to maintain coritainmrent integrity. Each remote-manual containment isolation valve is installed in a 6ontainment penetration associated with a closed piping system. Since these valves do not perform a containment isolation function, RG 1.97 control room indication of their position is not needed.

ENCLOSURE

V Local-manual containment isolation valves are administratively controlled and their containment isolation function is verified by the in-place administrative controls governing their positioning.

Since these valves cannot reposition automatically, it is not necessary to reverify their position after a containment isolation signal. Therefore, RG 1.97 control room Indication of the position of these valves is not necessary.

The licensee has not provided the recording capability of the position of containment Isolation valves. The purpose of the control room indication of the position of containment Isolation valves is to provide the operator with the status of containment penetrations. There would not be a significant benefit from recording the position information; thus, the recording of containment Isolation valve position Information Is'not necessary.

3.0 CONCLUSION

Based on review of the licensee's submittal, the NRC staff finds that the licensee has provided

.adequate justification for deviations from the RG 1.97, Revision 2, recommendations for the instrumentation that monitors containment Isolation valve position at Point Beach, Units 1 and 2.

Principal Contributor: B. Marcus Date: February 22, 2002 I

NMMU Committed to Nuclear Excellence n

Point Beach Nuclear Plant Operated by Nuclear Management Company, LLC NRC 2001-047 RG 1.97 July 27.2001 U.S. Nuclear Regulatory Commission AAITN: Document Control Desk Washington, DC 20555 Ladies/Gentlemen:

DOCKETS 50-266 AND 50-301 SUPPLEMENT ON REGULATORY GUIDE 1.97 IMPLEMENTATION POINT BEACH NUCLEAR PLANT. UNITS 1 AND 2 During review of commitments to Regulatory Guide (RG) 1.97,;we discovered two issues requiing clarification. The first issue regards an inconsistency in the NRC Safety Evaluation dated September 29, 1992. The second issue involves an ambiguity in distinguishing between automatic and remote-manual containment isolation valves in ourprevious RG 1.97 subtnittals, which created the appearance of a deviatiohnfrom a commitment to RG 1.97-regarding containifent'isolatioh valve position indication.

The NRC staff had previously evaluated conformance to RG 1.97'at Point Beach and concluded that it was acceptable, as documented in safety evaluations'dated July 11, 1986 and September29, 1992.

Attachiment I contains a description and evaluation of these two issues, along with additional justification for classifying remote-manual valves at Point Beach in the same category as manual valves for purposes of RG 1.97 commitments regarding containment isolation valve position indication. We request that the NRC staff review these two issuess, along with our corrective action', and provide a safety evaliation that documents the acceptability of our response to'these issues and our continued conformance to RG 1.97 with the existing Point Beach design.

Sincerely, JG/ik

Attachment:

I Description and Evaluation cc:

NRC Regional Administrator NRC Resident Inspector NRC Project Manager PSCW 6590 Nuclear Road

• Two Rivers, Wisconsin 54241 Telephone: 920.755.2321 JUL 30 20011

Attachment I Page l of6 DESCRIPTION AND EVALUATION SUPPLEMENT ON REGULATORY GUIDE 1.97 IMPLEMENTATION POINT BEACH NUCLEAR PLANT. UNITS 1 AND 2 1.0 INTRODUCI1ON During review of commitments to Regulatory Guide (RG) 1.97, we discovered two issues requiring clarification. The first issue regards an inconsistency in the NRC Safety Evaluation dated September 29, 1992. The second issue involves ambiguity in distinguishing between automatic and remote-manual containment isolation valves in our previous RG 1.97 submittals, which created the appearance of a deviation from a commitment to RG 1.97 regarding containment isolation valve position indication.

2.0 SAFETY EVALUATION INCONSISTENCY In a letter to NRC dated April 9, 1990, we provided a clarification to our implementation of RG 1.97 regarding the fact that Point Beach does not have recording'capability for containment isolation valve position to aid personnel in historical reconstruction of incidents. The basis provided in that letter to justify this exception to the RG 1.97 recommendations for Category I variables was that the Point Beach, "...Emergency Operating Procedures only require that the current status of containment isolation valve positions be deterrmined. Since there is presently more than adequate means available to reconstruct an operator's activities following an incident, (no) significant benefit would be realized by implementing a recording capability for containment isolation valve positions."

In response to that letter, the NRC Safety'Evaluatibn dated September 29, 1992, stated:

"Each remotely controlled containment isolation valve'has two control room indications of valve position. The redundant display of containment isolation valve position is an acceptable alternative to recording valve position."

This 1992 safety evaluation statement above does not appear to be reflective of the Point Beach design and is not consistent with the information provided in any RG 1.97 submittals from Point Beach. As stated in our 1983 RG 1.97 submittal position Indication on each containment isolation valve at Point Beach is not redundant. However, the isolation Itself Is redundant and is achieved by the use of redundant contairiment isolation valves (or one valve and a barrier).

An earlier NRC Safety Evaluation dated July,11, 1986, in response to our original RG 1.97 response correctly stated in section 3.3.3:

"...the licensee deviates from a stict interpretation of the Category '1 redundancy recommendation. Only the active valves have position'indication (i.e., check valves have no position indication). Since redundant isolation valves are provided, we find that redundant indication per valve [emphasis added] isrnot intended by the regulatory guide..... Therefore, we find that the instrumentation for'this variable is acceptable."

The NRC's 1986 safety evaluation appropriately evaluated the Point Beach design. The '1992 safety evaluation contains a statement regarding redundant position indication that is inconsistent with the 1986 safety evaluation and is not supported by our RG 1.97 submittals.

.swhys -a~-a Attachment I Page 2 of 6 We request that a new safety evaluation be provided that specifies the acceptability of the information above regarding the non-redundant containment isolation valve position indication. The new safety evaluation should also clarify that the lack of recording capability for containment isolation position is actually based on other adequate means available to reconstruct an operator's activities following an incident.

3.0 DISTINGUISHING BETWEEN AUTOMATIC AND IREMOTE-MANUAL VALVES The second issue regarding Point Beach RG 1.97 commitments involves ambiguity in our April 9, 1990, RG 1.97 clarification letter regarding the difference between automatic and remote-manual (power operated) containment isolation valves (CIVs) for purposes of applying RG 1.97 position indication criteria. Our original 1983 RG 1.97 submittal only considered automatic containment isolation valves that receive a containment isolation signal as requiring qualified position indication to meet the intent of RG 1.97. However, our original submittal did not communicate why RG 1.97 criteria were applied only to those valves and not to other types of valves that are also identified as CIVs in FSAR Section 52, such as manual valves. ihis created the potential for the NRC to misinterpret the extent of the containment isolation valves to which RG 1.97 criteria were applied.

Our April 9, 1990 letter purported to correct this potential misinterpretation by stating that,

"...Wisconsin Electric had only considered those containment isolation valves that receive a containment isolation signal." However, the letter also went on to state,"'...except for one valve per unit, all cbntainment isolation valves that can be remotely operated have remote position in dication in the form of indicator lights at the valve control switch." This statement could have been misinterpreted to extend the RG I.97 criterda beyond automatic valves 'that receive a containment isolation signal, to include otheicontainment isolation valves that are remote-manually operated from the control room.

The following background inforniation provides an explanation for the 1983 submittal limiting RG 1.97 criteria to automatic valves that receive a containment isolation signal.

RG-1.97 Submittal Background for Point Beach Prior to submittal of our 1990 RG 1.97 'Clarification' letter, we provided our initial RG 1.97 submittal in 1983. The 1983 submittal stated,

'Certain requirements of Regulatory Guide 1.97 were judged to be unnecessary or unreasonable to backflt in an operating plant. Justification is provided for those requirements to-which we'take exception. We believe'that no additional modifications are required forlthe protection of the public health and safety."

".-Supplement I to NUREG-0737 recomrmends submittal of a table which includes information... for each [emphasis added) Type A,'B, C, D, & E Yv'ariable.... Deviations from the guidance'in Regulatory Guide 1.97 (Revision 2 with errata) are indicated...'.

These statements indicate that'the commitment regarding valve position indication made in the 1983 submittal was intended to extend pnl& to those valves explicily listed in Table ', Containment Isolation Valve Positions,' included in that 1983 submittal. Notes h & i to the submitted table identify deviations regarding redundant position indication and emphasize which valves will be environmentally qualified. This 1983 submittal was endorsed by a 1986 NRC Safety Evaluation Report.

Attachment I Page 3 of 6 A subsequent internal audit finding indicated that our 1983 submittal did not clearly communicate the fact that we had applied the RG 1.97 position'indication criteria only to those CIYs that receive an automatic signal. Our response to this finding resulted in the April 9, 1990 Clarification'letterto document our deviation from the RG-l.97 guidance for all CIVs that do not receive an automatic signal. The 1990 letter also included justification for this deviation.

The 1990 letter stated, '...Wisconsin Electric had only considered those containment isolation valves that receive a containment isolation signal." This statement is followed by a description (stitiment of fact) regarding the existing position indication for automatic CIVs, a statement that most remotely operated CIVs have position'indication; and that manual CIVs have no position indication.- This description statement is followed by the admission that, "...we may have inadvertently implied that all containment isolation valves except check valves... have remote position indication at Point Beach.

...the system as presently designed (emphasis-added) along with the present administrative controls for controlling valve position provide adequate assurance of containment isolation conditions." These statements in 'the 1990 letter are followed by a detailed justification for deviating from the RG-1.97 guidelines for locally-operated manual CIVs.

These statements 'in the 1990 letter were not a commitment that all remotely operated CIVs would have remote position indication. Rather, they merely described the existing Point Beach design and why this design was acceptable. "The 1990 letter did not provide a revised Table I listing all (or additional) affected CIVs, as per the original RG-1.97 submittal request.

However, the 1990 letter'did not clearly disiingigish between automatic valves which receive a containment isolation signal and remotely-operated manual valves (which are power operated valves that do not receive an automatic actuation signal). This created ambiguity regarding the RG 1.97 applicability to position indication on remote-manual valves. 'The 1992 NRC SER on this'condition appears equally ambiguous. Nevertheless, 'the justification provided in the 1990 letter for deviation from the position indication guidelines in RQI4.97 is applicable'to both locally-operated, manual valves and remotely-operated nianual alves at Point Beach.

Additional Justification for Exempting Remote-Manual Valves from RG 1.97 Table 2 in AG 1.97 recommends Category 1 position indication of containment isolation valves to monitor "accomplishment of Isolation". Point Beach remote-manual valves do not perform an active containment isolation function that'requires their closure'to maintain containment integrity. The basis

'for this statement is that each remote-manual valve listed as a containment isolation valve in FSAR Section 5.2 is installed in a containmentpenetration associated with a closed piping system.

LN mtK UI -VtI Attachment I Page 4 of 6 Specifically, the fluid penetrations containing remote-manual containment isolation valves are associated with closed systems forMain Steam, Residual Heat Removal, Component Cooling Water, and Safety Injection. Each of these closed systems is considered a passive containment barrier (similar to the containment liner plate). As a passive barrier, a closed system is not postulated to immediately fail following a LOCA. For the containment function, only active component failures are postulated to occur per'the Point Beach General Design Criteria.' Therefore, the containment function is satisfied by the closed system alone, and remote-manual valves are not required to reposition to perform the containment isolation function. Remote-manual valve repositioning may be needed for other reasons related to post-accident system operation. Therefore, although control room position indication of remote-manual valves is useful forsystem operation post-accident, position indication is not required to monitor accomplishment of the containment isolation function.

Power-operated vaives'in general are susceptible to an active -electrical failure, whereas local manual valves without power operators are not susceptible. "If such a failure occurred to reposition a remote-manual containment isolation valve, there would be no consequence to containment integrity because the associated passive closed system containment barrier would remain intact. Although detection of

-a spurious valve repositioning using control roorn position indication would be useful to the operator for diagnosing system status, it is not needed on remote-manual CIVs to monitor accomplishment of the containment isolation function.

Therefore, control room position indication of remote-manual containment isolation valves does not support monitoring of the containment isolation function at Point Beach following an accident and is not needed to meet the intent of RG 1.97 Table-2 for Type B variables.

In our Technical Specifications, Post Accident Monitoring (PAM) instrumentation for containment isolation valves applies only to active containment isolation valves. The term "active containment isolation valves" refers to those automatic Valves that receive a containment isolation signal to actively change position following a design basis accident.2 From a containment fuictional standpoint; remoie-manual containment isolation valves are not active valves because they do not require mechanical movement (closure) to perform a containment

. isolation function. Remote-manual containment isolation valves can remain either open or closed following an accident because all such valves are a'ssociated with closed piping systems, which Lprovide a passive containment barrier regardless of the valve's position.

For the above reasons, automatic containment isolation valves are considered to be only those containment isolation valves that receive a containment isolation signal. This interpretationis consistent with Sections 5.2 and 7.6 of the Point Beach FSAR.

Manual valves at Point Beach (including remote-manual valves) deviate as a group from the RG 1.97

,guidance for position indication. Thejustification for this deviation, provided in the 1990 letter,

.remains germane to both local-manual and rernote-manual valves. Those remote-manual containment

,isolation valves that have position indication installed have this indication only as a design feature.

This feature is not subject to the commitments for RG 1.97 qualification 'citeria applied to the automatic containment isolation valves.

Section 4 of ANSIIANSg58.9-1 981, Slngle Failure Criteria for Ught Water Reactor Safety-Related Fluid Systems, also exempts containment vessels and containment Isolation systems from passive failures 2

For single failure purposes, an active component reli6s on mechanical movement to accomplish Its function upon demand (Ref. ANSVANS-58.9-1981 Section 2).

Attachment I Page 5 of 6 Our 1990 letter also identified one remotely operated containment isolation valve per unit that lacked position indication. This one valve without indicator lights was a vent valve for the nitrogen supply to the SI accumulators. This vent valve was later reclassified and noilonger serves as a containment isolation valve. Another remote-manual CIV-(CV-133) also does not have position indication, as discussed below.

Clarification Regarding Lack of Position Indication for Valve CV-133 CV-133, the RHR System-to-CVCS letdown isolation valve, is a remote-manual valve identified in FSAR Section 5.2 as a containment isolation valve associated with penetration P-B and the closed RHR system. CV-133 was designed and built without control room position indication. It is remotely operated by a position demand controller.in the control room. Based on the previous discussion, similar to other remote-manual CIVs, CV-133 does not perform a containment isolation function and does not require position indication to meet the intent of RG 1.97.

In 1999, a Licensee Event Report (LER,1999-004-00) was written concerning the Unit 2 CV-133 valve. The LER concerned the failure'to enter a Technical Specification action statement for inoperable containment isolation valves following detection of leakage through the normally-closed valve. Because CV-133 is associated with a closed system in an essential penetration and does not function as a containment isolation valve, a6corrective action identified in the LER was to pursue reclassification of CV-133 to remove the CrV designation. Additionally, an FSAR statement regarding the existence of position indication for all remote-operated valves in the control room will

• be revised to eliminate inconsistencies with the ag-built plant:

'During normnal operation, CV-133 provides a barrier against primary coolant in te' letdown system piping leaking'into the RHR piping that exits containment. However, the primary containment function for essential penetration P-8 is provided by the RHR system being a closed system outside containment. 'In the event of a design basis accident, essential penetration P-8 will provide a low-head safety injection 'flowpath. During long term recirculation cooling, this flowpath will contain primary coolant. In this mode of operation, CV-133 would not perforim any containment isolation function since the penetration floipath will be open and primary cdolant would be flowing through the RHR piping outside containment. Therefore, there is no operational need to monitor CV-133 valve position for the containment function during a design basis accident.

Conclusion Based on the Point Beach system design, all remote-manual containment isolation valves at Point Beach, including valve CV-133, do not fall within the guidelines for position indication recommended by RG 1.97. The only c'ontainment isolation valves to which RG 1.97 position indication criteria have been applied at Polnt Beach are'those automatic valves that receive a containment'isolation signal. This was the intent of our 1983 submittal, and therefore we request that a new safety'evaluation be provided that specifies the iacceptability of this information.

LNKM 1I-UU1I Attachment I Page 6 of 6

4.0 REFERENCES

1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident" (Revision 2)

2. ANSI/ANS-58.9-198 1, Single Failure Criteria for Light Water Reactor Safety-Related Fluid Systems

. II.-

- __

/POlNT BEACH NUCLEAR PLANT CLRT TESTING PROGRAM

/ CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 BI DFebruary 25, 2004 K BASIS DOCUMENT/

I ATTACHMENT 3 PENETRATION REVIEW Main Steam Penetration I & 2 Class Requiremnents Normal Function Post LOCA Function Drawing s Leakage Barriers:

( nside Containment ClSyste P2 Inside Containment Closed System 4

Non-Essential Open - supply main steam Open - services to aux. feedwatcr turbine, pressure relief and cooldown Unit 1:

M201S-SH.1 Unit 2:

M2201.SH.J Outside 'C6ntainment MS-227 MS-201 8 MS-23 4 MS-235 Outside Containment MS-244 MS-2017 MS-236 MS-238 MS-237 la5 Main steam is part of a closed system inside containment and considered an extension of the containment liner plate. Valves designated as CIVs for this penetration do not require leak testing as described in Section 2.2.1 of this testing basis document. Additional closed system testing is not j

required since the pressure of the closed system, the secondary side of the steam generator. is at or above containment design pressure during normal 'operations.

Failure of the closed system steam generator boundary is limited to I gprn as described in Attachment 2.

Additionally, primary to secondary leakage is limited by'TS 3.4.13.d to 500 GPD.No action for leakage

• of the 'closed system boundary.up to this point'is required with respect to the containment boundary.

Isolation of the leaking portion of the closed system is allowable when possible. Additional LCO action statements may be required depending upon the function of the isolated portion of the closed system.

See Attachment 2 for closed system boundaries.

Actions for a failed containment isolation valve are directed by TS 3.6.3.Cand require the flow path for the affected penetration to be isolated. Isolation of either main steam penetration will be operationally restrictive and require a plant shutdown.

Pace 40 of 138

POINT BEACH NUCLEAR PLANT CONTAINMENT LEAKAGE RATE TESTING PROGRAM BASIS DOCUMENT CLRT TESTING PROGRAM Revision 6 February 25, 2004 ATTACHMENT 3 PENETRATION REVIEW The penetration may be opened for intermittent use under administrative controls of OM 3.2.7.

l Dedicated Operator as allowed by TS 3.6.3.

l Other requirements of TS 3.7.1, TS 3.7.2, TS 3.7.4, TS 3.7.5 may apply depending upon the affected containment isolation valve.

NEI 94-01 Revision 0 NUCLEAR ENERGY INSTITUTE INDUSTRY GUIDELINE FOR IMPLEMENTING PERFORMANCE-BASED OPTION OF 10 -CFR PART 50; APPENDIX J July 26, 1995

.at

't:_~

ii

-i V

E 6.0 GENERAL REQUIREMENTS Option B of 10 CFR 50, Appendix J states, in part, that a Type A test which measures both the containment system overall integrated leakage rate at the containment pressure and system alignments assumed during a large break loss of coolant accident (LOCA), and demonstrates the capability of the primary containment to withstand an internal pressure load may be conducted at a periodic interval based on the performance of-the overall containment system. The leakage rate must not exceed what is allowed as specified in a plant's Technical Specifications.

A review of leakage rate testing experience indicates that only a small percentage of Type A tests have excessive leakage. Furthermnore, the observed leakage.rates for the few Type A test failures were only marginally above current limits., These observations, together with the insensitivity of public riskoto containment leakage rate at these low levels, suggest that for Type A tests, intervals may be established based on performance. Type A test is the primary test to detect significant leakage from the containment that would not be detected by the Tape B and Type C testing:programs, and to verify at periodic intervais the accident leakage (La) assumptions in the accident analysis. Specific details of Type A test requirements are discussed in ANSIANTS 56.8-1994.

An LLRT is a test performed on Type B and Type C components. An LLRT is

-not required for the following.cases:

• Primary containment boundaries that do not constitute potenrial'prima-v containment atmospheric pathways during.and.following a Design Basis Accident (DBA);

• Boundaries sealed with aqualified sealrsystem, or, Test connection vents and drains between primary containment isolation valves which are one inch or less in size, adniinistratively secured dosed and consist of a double barrier.

For Type B and Type C tests, intervals shall be established based on the performance history of each component. Performance criterion for each component is determined by designadng'an administrative leakage limit for ea-ch -component in the Type B and Type C testing program. The acceptance criteria for'Ty-pe B and Type C tests is based upon demonstrating that the sum of leakage rates at DBA 4

CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 I DFebruary 25, 2004 1.0 PURPOSE 1.1 This basis document establishes the containment leakage testing requirements associated with implementing 10 CFR 50 Appendix J Option B, including the extent and type of testing required for each'component. In the course of developing this document, the containment structure and each system penetrating the containment structure were evaluated with respect to the function of providing containment isolation.

1.2 Leak testing components of the containment system is accomplished through Type A.

Type B and Type C testing as defined in 10 CFR 50, Appendix J Option B. (TS 5.5.15) directs this Containment Leakage Rate Testing Program to be in accordance with Regulatory.Guide 1.163, "Performance-Based Containment Leak-Test Program." NEI 94-01, "Industry Guide for Implementing Performance Based Option of 10 CFR 50, Appendix J" was endorsed by the NRC with exceptions. NEI194-01 used the performance based approached due the negligible affect on the health and safety 'of the public as a result of extended interval testing as concluded in NUREG-1493, "Perfornance-Based Leak Test Program." Testing methods are provided by ANSI/ANS 56.8-1994, "Containment 'System Leakage Testing Requirements." Any additional requirements for testing the containment isolation function beyond 10 CFR 50 Ap'pendix J are also identified in this document to provide the reader with a comprehensive view of containment component testing requirements.

'2.0 DISCUSSION 2.1 The Containment System 2.1.1 The containment system provides an essentially'leak-tight barrier against the uncontrolled release of radioactivity to the environment during the most limiting accident. The containment system is designed to maintain a leakage rate no greater than 0.41% of containment air weight per day iwhen subject to design pressure and temperaturc (60'psig, 2867F), humidities, chemicals.

missiles and other severe environmental conditions predicted in the event of a design basis loss-of-coolant accident (LOCA). The total containment leakage is administratively maintained less th'an 0.2 wt %/day.',A LOCA is the only design basis accident that relies on the containment system to limit radioactivity releases into'the envirohnent. The containment.sysrtem is the principal enclosure that acts as a leakage barrier, after the reactor coolant pressure boundary, to control the release of radioactiveimaterial from the fuel in the reactortcore u'nder design basis accident conditions. It'is comprised of.'

a. The primary containment structure, including access closures, penetration closures and appurtenances;

'N'L 99.0DS6 I AN'S ANS 56.8-1094. Section 2 Page 3 of 138

CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 February 25, 2004 BASIS DOCUMENT

b. Those valves, piping, closed systems, and other pressure retaining components used to effect isolation of the primary containment atmosphere from the outside environs; and

c. Those systems or portions of systems that, by their system functions, extend the primary containment structural boundary.

'2.1.2 The containment system is an Engineered Safety Feature.3 The containment system consists of the containment structure and all pathways that penetrate the containment structure Which can result in the release of radioactive material into the environment. The containment structure is a'pre-stressed, post-tension reinforced concrete cylinder with a flat base and shallow hemispherical dome. The 'interior of the structure is completely lined with a welded steel plate, commonly referred to as the liner plate. The liner plate, a single passive barrier,'acts as a membrane providing a barrier against vapor and gas leakage. Pathways that could result in leakage, such as fluid system piping that penetrates the liner plate, are designed with'barriers (e.g., valve, penetration or closed system) between the inside and outside of containment Containment system leakage barriers in the form'of the liner plate, penetrations, and valves are required to be tested in accordance with 10 CFR 50, Appendix J. Other containment system leakage barriers that form closed systems inside and outside containment are addressed in Sections 2.2.2 and -212.4,'respectively.

{

2.1.3 Appendix J requires Type A, Type B and Type C testing. A-Type A test is an

,Integrated Leak Rate Test (ILRT) on the entire containment system. The ILRT pressurizes the containment system to peak accident pressure 'and measures the total system leakage. A Type B or Type' C test is a local leak rate test

'(LLRT) which measures the leakage characteristics through individual containment penetrations and valves.

2.2 Isolation Barriers Isolation barriers are mechanical means for&preventing passage or release of fluid through

• fluid systems which penetrate the containment structure. The Point Beach Nuclear Plant (PBNP) containment isolation barrier design was governed by General Design'Criterion (GDC)-53. GDC-53 states, "penetrations that require closure for the containment'function shall be protected by redundant valving and associated apparatus.' 5 The FSAR explains that each system whose piping penetrates the containment liner plate is designed to establish and maintain isolation of the containment from'the outside environment in the event of a LOCA, concurrent with an independent failure or malfunction of any active system component. By'limiting failures to only "active" components, the concept of passive and active isolation'barriers is introduced.

'FSAR. Section 1.2.6. p. 6. June 1 996 ANSVANS 56.2-1984. Containment Isolation Provisions for fluid Syslerns After2 LOCA. p. 2

'FSAR.Section5.2. pJui+/-.-e L

Pagc 4 of 138

CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 February 25, 2004 BASIS DOCUMENT An active component is defined as one in which mechanical motion must occur to perform the components intended safety function.6 ANSIIANS-56.8-1994. "Containment System Leakage Testing Rcquirements" defines an active failure-as. "a malfunction.

excluding passive failures. of a component which relies on mechanical movement or change of state to complete it's intended function upon demand. Examples of active failures include the failure of a valve or a check valve to move to it's correct position. or the failure of a pump, fan, or diesel generator to start." A passive component is deemed as one which mechanical movement'feed notfoccur in order for the component to perform it's intended safety function.. Examples of passive isolation barriers are closed systems, welded flanges and the liner plate itself. PBNP was originally designed with single isolation barriers for passive components and redundant isolation barriers for active components under the design premise 'that passive components do not'fail, and therefore do not require redundant barriers. Additional requirements that added redundant isolation barriers to passive components were imposed as a result of licensing agreements with the Nuclear Regulatory Commission (NRC).

License requirements are captured in the FSAR and various correspondence between PBNP and the NRC. In general, for each line that penetrates the containment structure that is part of the reactor coolant boundary, or which directly connects'the containment atmosphere to the outside environment, two isolation barriers are provided. The only exception to this general rule is for closed systems inside containment that act as single passive isolation barriers. Closed systems inside containment are considered'extensions of the containment liner plate and not designed with redundant isolation barriers, even though valves outside of containment were designated as redundant isolation' barriers in the FSAR as part of our licensing agreement. The valves designated as isolation barriers in these systems are not required to be tested in accordance with 10 CFR 50, Appendix J (see item c below forjustifilcation).

Additional commitments were made to the NRC as a result of the Three Mile Island (TMI) accident in 1979. IE Billetin 79-06A, "Review of Operational Errors and System Misalignments Identified'During the Three Mile Island Accident,"

NUREG 0578, 'TMI-2 lessons Learned Task'Force Status Report and Short-Term Recommendations," and NUREG 0737, "Clarification of TMI Action Plan Requirements," 'esttblished:

• the designation of essential and non-essential systems that penetrate containment

• the requirement for redundant barriers in all non-essential lines

• and the requirement for h Leakage Reduction' and Preventive Maintenance (LRPM) program for systems outside containment that process primary coolant and could contain high level radioactive material post-accident ANSVANS-S6.g-1l'j4. Con'Canrnwtnt.yszem bealmeeTusting Requirwnmts. 'p. I ANS'ANS-56..I'J)84. conuinm'nt isoltion Prtvisirns torFluid SystrnsAricr a LOCA. p.3 Page 5 of 138

CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 February 25, 2004 BASIS DOCUMENT Each penetration's classification as either essential or non-essential is captured in of this document. All non-essential lines have redundant isolation barriers.

If an isolation barrier is not tested in accordance with 10 CFR 50, Appendix J, an explanation is provided. The LRPM program establishes the testing method and acceptance criteria for all closed systems outside containment that process primary coolant and could contain high level radioactive material.

2.2.1 Liner Plate

a. The leakage limiting barrier for the containment structure is the 1/4" thick welded steel liner plate. The liner plate is a passive component and acts as a single isolation 'barrier by design. To protect liner plate integrity during a LOCA, the liner plate was deliberately designed to be protected from LOCA-induced effects (e.g., missiles, jet impingement, etc.). Spare penetrations that are designed with welded pressure boundaries are considered extensions of the liner plate and tested only during an'ILRT.

L Penetrations which are designed with closed systems inside containment are'also considered extensions of the liner plate. The industry standard for a "closed system" inside containment according to General Design Criteria 57 for containment isolation are:

not communicate with either the primary coolant or the containment f atmosphere be missile, pipe whip, and jet force protected meet Safety Class 2 design requirements withstand temperature equal to containment design temperature withstand external pressure equal to containment structural integrity test pressure w'ithstafnd loss-of-coolant accident transients and environment e

meet Seismic Category I design requirements be protected against over-pressure from thermal expansion of contained fluid when isolated be capable of leak testing during a Type A test AN'SVANS56,2.I984.'ContainrmnI Isolation lrovisions ror Fluid Systenis Aftcra LOCA. p.8 Page 6 of 138

CONTAINMENT LEAKAGE RATE TESTING PROGRAM Revision 6 February 25,)2004 BASIS DOCUMENT

b. Although PBNP was not licensed to ANSI/ANS 56.2. this definition provides industry guidance. The PBINP licensing requirements for closed systems either inside or outside containment are protected against missiles and high energy line breaks and arc designed in accordance with Class I seismic criteria. Their design pressure is higher than the containment design pressure. Closed systems meeting this criteria are designed such that the single passive pressure barrier remains intact during a LOCA.10 There are three system that meet these requirements: steam generator secondary side, component cooling water, and service water. The associated systems are 'not subject to rupture following~a LOCA. " 1 In 1972, the Westinghouse Steam System Design Manual referred to the steam generatortpressure boundary as equivalent to an extension of the containment liner plate and specifically states that, 'the valves associated with the main steam, feed, blowdown and sample lines do not have to meet containmentlisolation criteria since they are.not [isolation]

3 barriers."12 This was consistent with original PBNP design criteria.' 3 Additionally, with the first requirement that the closed system does not communicate with'containment atmosphere, Appendix J testing is not required for containment isolation valves designated in closed systems since that boundary'does not constitute potential containment atmospheric pathway during and following a design basis accident.' 4

c. As part of PBNP's operating license application, the NRC required PBNP to designate at least one CIV valve external to containment for penetrations which'have a low robability onrpturediing a LOCA (e.g., certain secon'dary'lines).' The PBNIl FFDSARdsIgnated 39 valves per unit (4-shut manual valves; 4 check val containment, 8 remotely operated valves and 23 open manual valves) as CMVs for these systems to address the NRC concerns. These Valves, which are not

-required by Emergency Operating Procedures (EOPs),to go shut either during or following a LOCA, arc not required to be Type B orType C leak tested because the associated closed system boundary does not constitute a potential primary containment atmospheric pathway due to the design

'features'listed above.'6 Additionally, the NRC has Tecognized that closed systems inside containment that are maintained at a'pressure at or above containment design pressure during normal operation are exempt from leak testing p./.....

FSAR 5.2.2.. Explan tory Notes for coniainmun Furos. NowO

"'CR9S-17S' #1-

' Unit I PreliminarySSafeti Analysis Report (PSAR). p. 5-41 S :-Wessinghouse. Steam Syvston Design tN1Jnul, p. IV-'. 1/72

'Westinshouse. I' riecfiinCriti(ria and Recomnmnendtions Against Cuinidmnt Failure of Renctor Coolant Sysiem and Containtnent Inegrity.

p. I. April 1967 NFI 94-01. 'Industry Guideline for Implementing Perfomnncie-Based Option or 10 CFR 50. Appendix I. p. 4. July 26. 1995 l! Unit I PSAR.Supplement 1.p. 78-1. 12/14/1966

" ANS1IANS-56.8-1 994. 'Cuntainment System -cakiage Tesling Rcquircrnents: Section 33.1. p. 6 1T Rgulzcory Guide 1. 141. 'Containnmnt Isol ion Pworisions For Fid Systerns. p. C. I. April 1978 Page 7 of 138