ML20151L260

Provides Addl Info to Facilitate NRC Review of Util 880407 Request for Schedular Exemption from Requirements of 10CFR50.49(j) Re Bunker-Ramo Electrical Penetration Assemblies

ML20151L260
Person / Time
Site:	Braidwood
Issue date:	04/15/1988
From:	Lentine F COMMONWEALTH EDISON CO.
To:	Murley T Office of Nuclear Reactor Regulation
References
4500K, NUDOCS 8804220005
Download: ML20151L260 (21)

Text

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f ^ '~' Commonwealth N Edison

( ,_ ) One First Nabonal Plaza, CNea0o, lHinois

(' v Address Reply to: Post Ot' ice Box 767 CNeago, IMinois 60690 0,'67 April 15, 1988 Mr. Thomas E. Murley, Director office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555 P

ATTN: Document Control Desk

Subject:

Braidwood Station Unit 2 Schedular Exemption Request.

NRC Docket No. 50-457 j, '

1 *' References (a): April 7, 1988 letter from S.C. Hunsader to T.E. Murley (b): April 7, 1988 letter from S.C. Hunsader to T.E. Murley (c): March 23, 1988 letter from S.C. Hunsader to T.E. Murley

Dear Mr. Murley:

The purpose of this letter is to provide additional information to facilitate the NRC's review of Commonwealth Edison's request for a schedular

. exemption. This temporary exemption from the requirements of 10 CFR 50.49(j) was initially requested in reference (a). This exemption involves Bunker-Ramo

! electrical penetration assemblies installed in Braidwood Unit 2. Conunonwealth i Edison has been unable to convince the NRC staff that this equipment meets the

< environmental qualification requirements of 10 CFR 50.49. As a result, a temporary exemption from compliance with this regulation was requested to  ;

allow the full power licensing of Braidwood Unit 2 to proceed.  ;

This letter contains additional information to demonstrate the following:

o granting this temporary exemption will not present an undue risk to the public health and safety (10 CFR 50.12(a)(1))

i e special circumstances are present in that compliance would result in undue hardship or other costs...that are significantly in excess of those incurred by others similarly ,

1 situated (10 CFR 50.12(a)(2)(iii)). '6  !

l i\

8804220005 880415

! PDR ADOCK 05000457 P DCD i

T.E. Murley April 15, 1988

• special circumstances are present in that the exemption would provide only temporary relief from the applicable regulation and the licensee has made good faith efforts to compic with the regulation (10 cFR 50.12(a)(2)(v)).

Enclosure 1 contains a detailed safety evaluation which demonstrates that granting this temporary exemption will not present an undue risk to public health and safety. The safety evaluation contains two parts. part 1 shows that the automatic safety functions which must be accomplished to cope with the relevant accidents will not be impaired by the electrical penetrations in question. part 2 of the safety evaluation contains a detailed failure modes and effects analysis (FMEA) of the instrumentation channels potentially affected by the electrical penetration deficiency. This set of analyses examines the potential effect of erroneous control room indications on the proper accomplishment of operator actions following the relevant accidents.

This set of analyses shows that the emergency operating procedures, even with the erroneous post-accident indications, will assure that operators take the appropriate recovery actions.

Enclosure 2 contains an evaluation of the economic impact associated with replacing the electrical penetration assemblies now. This evaluation shows there would be significant replacement energy costs that would cause an undue hardship to Commonwealth Edison's ratepayers. Replacing the electrical penetrations now would also delay the in-service date for Braidwood Unit 2.

This could cause commonwealth Edison undue economic hardship significantly in excess of that incurred by others similarly situated, commonwealth Edison has made a good faith affort to comply with 10 CFR 50.49 as it applies to she electrical penetration assemblies. Significant efforts have been made to produce evidence that demonstrates the existing electrical penetrations are fully qualified. These efforts are documented in references (b) and (c).

preparations have begun for replacement of the instrumentation penctrations. Enclosure 3 part 1 provides a breakdown of the required activities and estimated schedule for replacment. The estimated duration for the replacement program is 16 weeks. Therefore, the earliest ihe replacement program could be completed would be September 20, 1988.

Enclosure 3 part 2 documents Commonwealth Edison's investigation of the feasibility of a new test program to show the existing electrical penetrations are environmentally qualified. The only technically feasible option would be to prepare a detailed manufacturing and performance specifi-cation and have a "duplicate" penetration assembly fabricated by a qualified manufacturer. This effort is estimated to take 6 months to complete and would therefore take longer tiin the replacement program discussed above.

4 T.E. Murley April 15, 1988 We have undertaken these programs in parallel in a' good faith effort to demonstrate in the most expeditious manner possible, our full compliance with 10 CFR 50.49.

Reference (a) stated that the penetration assemblies would be replaced prior to startup following the first refueling outage. Commonwealth Edison hereby modifies that commitment to state that the replacement will be accomplished no later than startup following the surveillance outage presently scheduled for January, 1989. If an unscheduled outage of sufficient duration occurs after September, 1988, the replacement will be accomplished at th.1t time. This date would provide sufficient planning time to reduce the tinv for replacement to an acceptable duration of approximately 10 weeks. In view of the positive conclusions of the safety evaluation provided in Enclosure 1, d.t is our judgement that delaying the replacement until the surveillance outage of January, 1989, will result in insignificant incremental risk. ,

commonwealth Edison believes the information provided in this letter j demonstrates that issuance of this schedular exemption will not present an undue risk to public health arai safety and that special circumstances are present. These conditions saticfy the requirements oi 10 CFR 50.12.

Very truly yours, P. G. Lentine pWR Licensing Supervisor klj Enclosure 4500K

KNCLOSURE 1 SAFETY EVALUATION f INTRODUCTION The instrumentation penetration assemblies are designed to carry the electrical signals from instrumentation inside the containment to main control room indicators and protective circuitry, wnile maintaining the integrity of the containment pressure boundary. The potential deficiency in the environ-mental qualification of the electrical penetration assemblies has no effect on the pressure-retaining capabilities of the assemblies, but could potentially affect the electrical signals transmitted through the penetration modules.

The specific instrument channels involved provide certain inputs to the reactor protection system and engineered safety features actuation system.

They also provide certain post-accident monitoring func*. ions. Some of these functions are required to mitigate a LOCA, main feedwater line break, and a main steamline break. These are the accidents that produce the harsh environment the penetrations must withstand.

Part 1 ACCOMPLISHMENT OF AUTOMATIC SAFETY FUNCTION BY OTHER EOUIPMENT_

A review was conducted of the FSAR accident analyses for a loss of coolant accident (LOCA), main steamline break, and feedwater line break to determine the instrument channels relied upon to initiate the necessary automatic protective functions in the reactor protection and engineered safety features systems. The results of this review indicated that in all cases the containment pressure and/or steamline pressure instrument channels were available to accomplish the required safety function. These instruments are located outside the containment and would not be affected by the accidents which produce the harsh environment at the electrical penetrations in question. An evaluation of the three accident analyses is presented below.

LOCA Table 15.6-1 of the Byron /Braidwood FSAR lists the time sequence of events for s spectrum of large break LOCA's. This table indicates that a reactor trip and safety injection will occur within 1.4 seconds. This actuation is expected to result from a low pressurizer pressure signal. Since the pressurizer pressure instrument channelt are connected to the suspect electrical penetration assemblies, another protective function must be available to mitigate the consequences of the LOCA. The instrument chcnnels which sense containment pressure will perform the necessary safety function.

The containment pressure instrument chaanels are located outside the containment. They are rot connected to the electrical penetration assemblies in question. These instruments (3 channels) will initiate a safety injection /

reactor trip signal at the high containment pressure (Hi-1) setpoint of 3.4 psig. A review of PSAR flytte. 15.6-12, 15.6-12a, 15.6-27, and 15.6-33

indicates the containment pressure will reach 3.4 psig in approximately 1 second following a large break LOCA. Therefore, the necessary automatic safety function will be accomplished in the timeframe assumed in the large break LOCA analysis.

MAIN STEAMLINE EREAK Section 15.1.5.1 of the FSAR discusses the analysis of a steamline rupture. The analysis states that a safety injection, and resulting reactor trip, will be actuated from any of the following: (1) low steamline pressure signals, (2) low pressurizer pressure signals, (3) high-1 containment pressure signals.

The steamline pressure and containment pressure instrument channels are located outside the containment. They are not connected to the electrical penetration assemblies in question. The steamline pressure instruments (4 channels) will initiate a safety injection, and resulting reactor trip, upon sensing low steamline pressure (640 psig) in any one loop. This should be sensed in less than 5 seconds after the steamline rupture (ref. FSAR p.

15.1-21).

The containment pressure instruments (3 channels) will initiate a safety injection / reactor trip signal at the high containment pressure (Hi-1) setpoint of 3.4 psig. This should occur in less than 10 seconds according to FSAR figure 6.2-13.

According to FSAR figures 15.1-16 and 15.1-19, a safety injection would be initiated in approximately 12 seconds by low pressure signals (1829 psig) from the pressurizer pressure instrument channels. Since these instruments are connected to the suspect electrical penetration assemblies and could be biased inthe non-conservative direction, they cannot be taken credit for to actuate a safety injection. This is of no significance because the automatic safety injection function will be accomplished in the same time or less by the steam 11ne pressure or ccntainment pressure instrument channels.

In addition to the safety injection and reactor trip functions, the accident analysis states that the feedwater isolation function will actuate following a steamline rupture. The feedwater isolation function will not be affected by the environmental qualification issue because it is actuated from a safety injection or reactor trip signal. As noted above, the safety injection function will be actuated by either low steamline pressure signals or high containment pressure signals.

Finally, the accident analysis states that the steamline isolation function will be actuated by signals from the steamline pressure or containment pressure instrument channels. As mentioned above, these instruments are located outside the containment and are not connected to the suspect olectrical penetration assemblies. Therefore, the steamline isolation function will actuate within 10 seconds as stated in the accident analysis (PSAR p. 15.1-21).

i MAIN FEEDWATER LINE BREAK section 15.2.8.1 of the FSAR discusses the analysis of a feedwater line rupture. The analysis states that a reactor trip will occur on any of the following conditions: (1) high pressurizer pressure, (2) overtemperature d T, (3) low-low steam generator water level, (4) safety injection.

Although the accident analysis does not take credit for the high pressurizer pressure reactor trip, this trip signal would normally actuate in approximately 40 seconds when pressurizer pressure reaches 2385 psig (ref. FSAR figures 15.2-14 and 15.2-18). Hcwever, the pressurizer pressure instrument channels are connected to the electrical penetrations in question. The potential low insulation resistance in the penetrations would cause the pressurizer pressure instruments to read erroneously high. Refer to Part 2 of the safety evaluation for an explanation of this. With the pressurizer pressure instruments biased high, the reactor trip on high pressurizer pressure will occur in less time than depicted on FSAR figures 15.2-14 and 15.2-18. This is conservative.

According to FSAR figures 15.2-15 and 15.2-19, a reactor trip would be actuated by the overtemperature 4T circuit in approximately 40 seconds.

Inputs to the overtemperature AT circuit include reactor coolant hot and cold leg narrow range temperature, pressurizer pressure, and power range neutron detectors. All of these instrument channels are connected to the suspect electrical penetrations. This is of no consequence because the accident analysis does not take credit for this reactor trip.

FSAR table 15.2-1 lists the time sequence of events for a feedwater system pipe break and indicates that a reactor trip will occur in 29 seconds when the low-low steam generator level trip setpoint is reached in the affected steam generator. Since the steam generator level instruments are ,

connected through the electrical penetrations in questiona and will therefore be biased in the non-conservative direction, they are considered  ;

unavailable to perform the reactor trip function. However, the reactor trip '

will occur on high pressurizer pressure in about the same time as the q low-low steam generator level reactor trip. Considering the erroneously l high reading of pressurizer pressure which would be present, the high ,

. pressurizer pressure reactor trip may occur sooner than the low-low steam generator level trip would have occurred.

The safety injection function, which also initiates a reactor trfp, would be actuated by low steamline pressure signals in any loop or from high

! containment pressure signals. According to PSAR table 15.2-1, the low steamline pressure setpoint of 640 psig would be reached in 374 seconds (322 without offsite power). Since the steamline pressure and containment pressure instrument channels are located outside the containment and are not 4 connected to the suspect electrical penetrations, they will function as stated in the accident analysf.s to actuato a safety injection.

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ENCLOSURE 1 Part 2 Failure Modes and Effects' Analysis for Post-Accident Monitoring Instruments Affected by Potential BO Deficiency Some of the instruments that could be affected by the potential EQ deficiency provide post-accident monitoring functions. Some of these functions are required to mitigate a LOCA, a main steam line break (MSLB),

or a main feedwater line break (PWLB), which are the accidents that produce the narsh environment the penetration must withstand.

A review was conducted of the Emergency Operating Procedures (BOP's) that are utilized for a primary or secondary line break to dd. ermine the instrument channels relied upon for operator actions. The results of this review indicated that one or more of the following conditions was met for all cases:

1) The preferred indication is qualified and is not affected by the potential qualification deficiency, or

2) A designated, qualified backup instrument is available to provide the information, or

3) The procedures provide alternative actions in the event that the item of information cannot be obtained. These actions are conservative with respect to maintaining critical safety functions (e.g., maintaining ECCS flow if termination conditions cannot be satisfied).

A summary of the results of this review was provided to the NRC in the letter of S.C. Hunsader to T.E. Murley of April 7, 1988.

This submittal provides the following additional information.

First, for each in.=trument affected, the type of instrumentation circuit is identified. Then i or each type of circuit, the failure mode (direction of error) is identified along with the basis for that determination. Then, for each instrument, the effect of the erroneous indication on the proper accomplishment of operator actions is evaluated.

The EOP's utilized in this evaluation are based on the Westinghouse Owners Group guidelines and have been reviewed and approved by the NRC staff. All R.G. 1.97 category A instruments that could be affected by the potential EQ deficiency have been included in the evaluation. ,

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Types of Instruments Affected DY Potential 80 Deficiency

- Parameter Type of Instrument Circuit

1. Reactor coolant temperature RTD

2. Reactor coolant flow Transmitter

3. Steam flow Transmitter

4. Steam generator level Transmitter

v. Pressurizer pressure Transmitter

6. Pressurizer level Transmitter

7. Reactor coolant wide range pressure Transmitter

8. Reactor coolant pump bearing water flow Tranumitter

9. Neutron flux Neutron detector t

t t

t

Figure 1 Effect of Reduced Insulation Resistance on RTD Circuit RTD Circuit Evaluation ---

, r--'

7 i i i I l ( iN sRn ll s e., lATo l l l I

1 1 I I L____J L___J Receiving Sensor (RTD)

Instrument (RTD ampilfer)

Where:

Rn = Norton equivalent resistance of twelving instrument iN = Norton equivalent current source of receiving instrument RnTo = Resistance of RTD R.q = Equivalent IR for cable, spilces, and penetration Under normal conditions R.q = oo, therefore the resistance seen by the receiving instrument is RRTD-Under accident conditions R.q # oo, therefore the resistance seen by the receiving instrument is:

Haro R.q Since this value is less than RnTo, Indication would de lower than C1595.045,M 04-88 actual process temperature.

Figure 2 Effect of Reduced insulation Resistance on Transmitter Circuit Transmitter Circuit Evaluation r-- 7 i RTs l l l 1 1 I I I

I

1. I I i,2

$"** I i

/ RI I

I I I v I I L _ _ _ _j  %  % L __. _ _ __I Receiving IS ensor GIN Instrument (transmitter)

(Power supply-signal converter)

Where:

VTH = Thevenin equivalent voltage of receiving Instrument RTs = Thevenin equivalent resistance of receiving instrument Rt = Transmitter load (variable) 13 = Transmitter output current i lN = Input current to receiving Instrument I,q = Leakage current due to decreased IR (equivalent)

R,q = Equivalent IR for cable, splices, and penetration Under normal conditions Req = w and I,q = 0.

Therefore, llN =IS Under accident conditions R,q # w and I,q # o.

Therefore, llN =IS + Ieq C1595.0441A 04-88 So on accident conditions l lN will be greater by 1,q.

This will cause the receiving instrument to read high.

-pn 3

1. Reactor Coolant Temperature Instrument numbers:

(narrow range) 2TE 411A 2TE 421A 2TE-431A 2TE-441A 2TE 411B 2TE 421B 2TE-431B 2TE-441B (wide range) 2TE RCO22A 2TE-RC022B 2TE RCO23A 2TE-RC023B 2TE RCO24A 2TE-RCO24B-2TE RCO25A 2TE-RCO25B Failure mode:

Reads erroneously low on decreasing IR Assessment:

The EOP's for LOCA, MSLB, and FWLB make limited use of reactor coolant temperature. For the design basis accidents, loss of offsite power results in a trip of all reactor coolant pumps, which renders the narrow range RTD's nonfunctional. Therefore, operators are trained not to use the narrow range RTD's for post accident monitoring applications.

1 BEP-0 Step 25 instructs the operator to "check RCS average temperature" to verify stable, no load temperature. (see also IBEP-ESI.1 Step 16). If temperature is low and decreasing, the operator is instructed to stop dumping steam and to shutdown unnecessary steam loads. The design basis LOCA and MSLB result in a substantial cooldown of the RCS, and therefore the operator will perform the specified actions. Erroneously low readings of reactor coolant temperature will result in no change to the actions performed.

For smaller LOCA's and FWLB's, erroneously low readings of reactor coolant temperature could cause the operator to stop dumping steam when continued steam d . is in fact necessary to prevent gradual heat-up of the RCS. If that were to occur, the RCS heat up would become apparent on the core exit thermocouples and the subcooling meter, which are unaffected by the potential EQ deficiency. It should be noted that the EOP critical safety function status trees are monitored on a frequent basis to verify adequate core cooling, with core exit thermocouples and subcooling as the specified parameters.

Reactor coolant temperature is also utilized to follow the progress of cooldown and depressurization following a small LOCA. (See 1BEP ES-1,2). While RCS wide range RTD's could be used for this purpose, the core exit thermocouples would also be utilized as confirming indications.

Erroneous readings of the wide range RTD's could delay the progress of the cooldown, but that is of minimal consequence in the post accident recovery phase. Adequate core cooling as indicated by core exit thermocouples would be maintained throughout the process, as required by the critical safety function status trees.

2. Reactor Coolant Flow:

Instrument numbers:

2FT 414 2FT-415 2FT-416 2FT-424 2FT-425 2FT-426 2FT-434 2FT-435 2FT-436 2FT-444 2FT-445 2FT-446 Failure mode:

Reads erroneously high on decreasing IR Assessment:

For the design basis accidents, loss of offsite power results in trip of all reactor coolant pumps, which results in zero reactor coolant flow. The EOP's for LOCA, MSLB, and FWLB make no reference to reactor coolant flow. Therefore, because reactor coolant flow is not a parameter of interest, erroneous indication will have no adverse effect.

3. Steam Flow Instrument numbers:

2FT 512 2FT-513 2FT-522 2FT-523 2FT-532 2FT-533 2FT-542 2FT-543 Failure mode:

Reads erroneously high on decreasing IR Assessment:

The EOP's for LOCA, MSLB, and FWLB make no reference to steam flow. For the action, "check if SG secondary pressure boundaries are intact," the operator is instructed to read SG pressure, which is unaffected by the potential EQ deficiency. (See for example, 1BEP-0 step 28 and 1BEP-1 step 2). If a MSLB or FWLB has occurred, the operator is instructed to identify the faulted SG by reading SG pressure (see 1BEP-2 step 3).

Therefore, because steam flow is not a parameter of interest, erroneous indication will have no adverse effect.

4. Steam Generator Level Instrument numbers:

(narrow range) 2LT-556 2LT-519 2LT-518 2LT-517 2LT-529 2LT-557 2LT-528 2LT-527 2LT-539 2LT-558 2LT-538 2LT-537 2LT-559 2LT-549 2LT-548 2LT-547

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.(wide range) 2LT-501' 2LT-502 2LT-504-2LT-503.

Failure mode:

Roads erroneously high on low IR Assessment:

The EOP's utilize SG narrow range level in several steps to verity secondary heat sink. (SG wide range level is not used) As an example,-for the action "check if ECCS flow should be terminated" (see for example 1

. BEP-0 step 31 and 1 BEP step 6), verification of secondary heat sink by means of so level'is one of four conditions thet must be satisfied to terminate BCCS flow. If SG 1evel-read erroneously high while the other

- three conditions (subcooling, RCS pressure, and PZR level) were satisfied, the operator could terminate BCCS flow prior to achieving the desired

< secondary heat sink capability. However, should degraded secondary heat sink capability result in heat up of the RCS, RCS subcooling would be gradually reduced, until it reached the value for which SI re-initiation is required (see 1 BEP-F1). Reinitiation of SI would restore the d',< sired core cooling.

So narrow range level is also used in diagnosis as one of the possible symptoms of So tube rupture. (see for example 1 BEP ES-0.0 step

3) However, the procedure checks for "any SG 1evel increasing in an uncontrolled manner", and an erroneously high reading resulting from low IR would more likely appear to be a constant positive offset rather than an "uncontrolled increase". If the operator went to the SG tube rupture procedure 1 BEP-3 he would be instructed to look for secondary high radiation as~a confirming indication. Because secondary radiation monitors are not affected by the potential EQ deficiency, the operator would correctly determine that no SG tube rupture was in progress.

5. Pressurizer pressure Instrument numbers:

2PT-455 2PT-456 2PT-457 2PT-458 Failure mode:

Reads erroneously high on low IR 7 l

e I

s

As20:sment pressurizer pressure is used only to determine if SI is required, if the setpoint has been reached and automatic SI actuation has not occurrod. For that case, procedure 1BEP-0 step 4 instructs the operator to manually actuate SI if pressurizer pressure or steamline pressure or containment pressure have reached the specified values. Erroneous indication of pressurizer pressure will have no adverse effect, because steamline pressure and containment pressure are unaffected by the potential BQ deficiency.

Should all pressurizer pressure channels fail offscale high, the pressure PORV's would inadvertently open. However, the EOP's contain explicit steps (see for example 1 BEP-0 step 26, 1 BEP-1 step 5) to check that PORV's are closed and to manually close their isolation block valves if necessary.

6. pressurizer Level Instrument numbers:

2LT-459 2LT-460 2LT-461 Failure mode:

Reads erroneously high on low IR Assessment:

The EOP's utilize pressurizer (pZR) level in several steps to verify adequate reactor coolant inventory. As an example, for the action "check if ECCS flow should be terminated" (see for example 1 BEP-0 step 31 and 1 BEP-1 step 6), verification of adequate reactor coolant inventory by means of pZR level is one of four conditions that must be satisfied to terminate ECCS flow. If pZR level read erroneously high while the other three conditions (subcooling, RCS pressure, and SG level) were satisfied, the operator could terminate ECCS flow prior to achieving the desired reactor coolant inventory. However, should insufficient reactor coolant inventory lead to heat up of the RCS, RCS subcooling would be gradually reduced, until it reached the value for which SI re-initiation is required (see 1 BEP-F1). Re-initiation of SI would restore the desired core cooling and reactor coolant inventory, i pZR level is used in 1 BEP-F1 as one of two parameters that must be monitored to determine if SI re-initiation is required. However, the other parameter, RCS subcooling, is not affected by the potential EQ deficiency; and the operator is instructed to manually actuate SI if either parameter reaches the specified value.

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PZR level is also used as to verify' adequate reactor coolant  ;

inventory in preparation for certain long term recovery actions in the post  ;

LOCA cooldown phase. (see 1 BEP BS 1.2 steps 11, 13, 14). These actions include starting reactor coolant coolant pumps (if offsite power is available) and stopping BCCS pumps that are not needed. .In each of these  !

steps, both pzr level and RCS subcooling must be above specified values. If  ;

par level read erroneously high and the operator took the specified recovery [

action prior to achieving the desired reactor coolant inventory, RCS  :

subcooling would be gradually reduced, until it reached the value for which j

SI re-initiation would be required.

7. Reactor Coolant Wide Range Pressure 2PT-406 2PT-407 Failure mede:

Reads erroneously high on low IR ,

4 Assessment:

i.

2PT-406 and 2PT-407 transmitters do not provide control room indication. All post accident monitoring functions that utilize reactor

, coolant wide range pressure use 2PT-403 and 2PT-405, which are unaffected by the potential sg deficiency. Therefore, erroneous readings of transmitters 2PT-406 and 2PT-407 would have no adverse effect. }

8. Reactor Coolant Pump Bearing Water Flow Instrument numbers:

2FT 651 l 2FT-654 2FT-657 2

2FT-660 Failure mode:

4 Reads erroneously high on decreasing IR l Assessment:

i For the design basis accidents, loss of offsite power results in a trip of all reactor coolant pucps. Bearing cooling water flow is not required if the pumps are tripped.

1BEP-F.O instructs the operator to trip reactor coolant pumps if

, cooling to the RCP is lost or containment phase B isolation has actuated.

For the design basis LOCA and MSLB, phase B isolation will have occurred.

if phase B isolation has not occurred, the operator will determine the I status of cooling to the RCP's by means of several indications. For the j

mz y; ,

action "check RCP cooling" (see for example IBEP ES 1.1 step 19) the operator is instructed to verify seal injection flow and to verify the following annunciators not lit:

RCP thermal barrier cc water flow low RCP bearing cc water flow low RCP thermal barrier cc water temperature high RCP bearing cc water temperature high If an erroneously high reading of RCP bearing water cooling flow falsely indicated adequate cooling when adequate cooling was not present, one or more of the above indications would correctly identify the cooling water problem. Because tripping the pump is the conservative action and has no adverse consequences (pump trip is part of the limiting scenario analyzed in the design basis accidents), the operator would take the appropriate action and would not be mislead by the single erroneous reading.-

9. Neutron Flux Instrument numbers:

(source and intermediate range) 2WR07E 2NR098 (power range) 2WR08E 2WR10E 2NR12E 2WR14E Failure mode:

Reads erroneously high on low IR (conservative assumption. Preliminary circuit analyses indicates little or no effect.)

Assessment:

Reactor trip occurs shortly after the occurrence of a LOCA, MSLB, or FWLB. For the action "verify reactor trip", procedure 1BKP-0 step 1 lists "rod bottom lights lit" and "reactor trip breakers open" as acceptable alternatives, along with "neutron flux decreasing." Therefore, erroneous indication of neutron flux does not prevent accomplishment of this step.

ENCLO6URE 2 Economic Impact of Electrical Penettation Replacement in Advance of Jsnuary, 1989 Surveillance Outage Commonwealth Edison has evaluated the potential economic impact associated with replacement of the electrical penetratica assemblies at Braidwood Unit 2 in advance of the scheduled January, 1989 surveillance outage. Ascuming that the required outage time is 16 weeks if replacement occurred now and the scheduled 6 week surveillance outage would be extended 4 weeks if replacement occurred later, replacement energy costs are

. estimated at $20 million. This includes a replacement energy cost estimate of $11/MWH in early 1987 dollars.

Replacing the electrical penetration 2 now would also result in a delay ~of the unit's in-service date. Therefore, additional accrual of  ;

allowance for funds used during construction (AFUDC), at approximately $15 '

million per month, would increase the cost of Braidwood Unit 2. Under the current regulatory environment, it is questionable whether or not Commonwealth Edison would be allowed to include this incremental cost in the rate base.

For the reasons stated above, Commonwealth Edison believes immediate compliance with the requirements of 10 CFR 50.49(j) could result in undue harship (economic costs) that is significantly in excess of that incurred by others similarly situated. These special circumstances meet the test of 10 CFR 50.12(a)(2)(iii).

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ENCLOSURE 3 part 1 Estimated schedule for Replacement of Electrical penetrations commonwealth Edison has begun to prepare for replacing the electrical penetration assemblies. The various activities and estimated schedule for this project are outlined below.

Engineering work is currently in progress to prepare a modification package. The modification package is a set of documents, including the design drawings which must undergo several layers of review. This is expected to be complete by May 17, 1988. When the modification package is near completion and the scope of the project is substantially defined, the construction department will begin to prepare an installation package. This will include a work sequence review in an attempt to optimize the efficiency '

of the installation effort. preparation of the installation package is expected to begin May 10, 1988 and be completed by May 31, 1988. In parallel with the effort to prepare an installation package, station personnel will initiate a review of the plant conditions required to perform the modification. The equipment required to be out-of-service for the modification will be reviewed against the technical specifications to assure all requirements are being met. This effort should be completed by May 31, 1988.

On May 31, 1988, work could begin to remove and install two of the four penetrations. Based on what is known now, we anticipate only being able to install two penetrations at a time because equipment out-of-service activities may be limited by the technical specifications. The removal and replacement effort for the first two penetrations is estimated to take four weeks. It should be completed by June 28, 1980. At this point, testing would begin to verify correct installation of the penetrations and functioning of the affected instrument channels. This testing should take about two weeks and, once completed, would allow the removal of the other two penetrations to begin. By July 17, 1988, removal and replacement of the other two penetrations could begin. We expect to complete installation of these penetrations by August 9, 1988.

At this point, a comprehensive testing program associated with all four penetrations would be initiated. All of the instrument channels .

affected by the modification would be thoroughly checked out. This should take about five weeks to complete. Based on this schedule, testing should be finished by September 13, 1988. If a containment integrated leak rate test is required, this would take an additional week. Therefore, the l project would be completed by September 20, 1988.

r-Sev rcl potcntiO1 problems could 1cngth:n tha schedulo outlined above. Full acceptability of the replacement penetrations on-site needs to  ;

be established. This includes a detailed inspection of the penetration i assemblies and a review of all pertinent quality assurance documentation. ,

NRC overview and acceptance of the project plan and testing requirements may i require some additional time. Temporary relief from some technical specification requirements may be needed to accomplish the modification.

The license amendment process would lengthen the overall schedule.

Installation or testing problems, beyond what have been accounted for in this estimated schedule, could also lengthen the duration of the project.

This modification is a complex project that involves approximately 75 instrument channels. The schedule outlined above does not allow a i sufficient amount of time to do thorough advance planning and "problem .

anticipation". Commonwealth Edison would prefer to delay this project to '

allow time for advance planning that would optimize the work activities and make the installation effort more' efficient. It may be possible to significantly reduce the duration of the project as estimated above.

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I Enclosure 3, part 2 Evaluation of Testing Option commonwealth Edison has considered the option of performing a new environmental qualification test of a Bunker Ramo instrument penetration assembly as a means of resolving this issue. We have determined that the option of replacement with environmentally qualified penetration assemblies of a different manufacturer is preferred over the testing option. The major factor in this determination is that a suitable penetration assembly is not presently available for testing. The original manufacturer, Bunker Ramo, is no longer in business. We have evaluated four other possible sources for a penetration assembly and have determined that each source has particular disadvantages. Tnese are discussed as follows:

1) Obtain a penetration assembly frou a cancelled plant.

Disadvantage As a result of plant cancellation, the penetration assemblies have been "abandoned" and have not been maintained in a controlled environment.

2 Damage or deterioration may have occurred to the point that performance may j be seriously degraded. Therefore, this option is considered technically j unacceptable.

2) Have ANCO Engineers "assemble" a penetration assembly from "spare parts".

Disadvantages ANCO Engineers acquired Bunker Ramo's remaining parts inventory and documentation files when Bunker Ramo went out of business. Those spare ptrts have not been maintained in a controlled environment. ANCO Engineers is not a manufacturing facility, and we have no basis for confidence in their ability to construct an assembly of the same quality as the original manufacturer. Finally, because documentation traceability of the spare parts has not been maintained, and because construction would be performed using different assembly processes by a firm other than the original manufacturer, we would not be able to establish similarity to the penetration assemblies installed at Braidwood 2. Therefore, this option is j considered technically unacceptable.

3) Remove a penetration module that is presently installed at Braidwood 2.

1 Disadvantages i' Removal of a penetration module requires a unit outage. The duration and outage impact for this work would be substantial. Although j spare (unused) modules are installed, removal would reduce the number of I spares which have been provided for future use. Making such a reduction at the beginning of plant life could hamper our ability to perform necessary

! plant modifications later in life. Therefore, this option is considered technically unacceptable.

4) prepare a detailed manufacturing and performance specification and have a "duplicate" penetration assembly fabricated by a qualified manufacturer.

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Disadvantages It is not known whether the manufacturing and performance specification can be prepared in sufficient detail-to establish similarity between the new penetration assembly and the penetration assemblies installed at Braidwood 2. Manufacturers of penetration assemblies with whom we might contrace for this work would have to construct special tooling and processes to produce a custom assembly different from the ones they currently manufacture. It is estimated that a minimum of six months would be required to prepare the specification and complete the fabrication of the new penetration assembly. To this would have to be added the time to perform the environmental qualification test, and the time for review and acceptance of the test results by both commonwealth Edison and the NRC.

Discussions with potential manufacturers would be required in order to determine the feasibility of this option and the validity of the estimated schedule. In view of the potential for delays in the manufacturing and testing processes, the schedule for this option may exceed that of the preferred option of replacement with environmentally qualified assemblies of a different manufacturer.

Also, because the possibility for test anomalies can not be ruled out, replacement with assemblies for which qualification has already been accepted would likely provide a more definitive resolution.